10-K 1 0001.txt FORM 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 FORM 10-K (X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended December 31, 2000 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition Period from to Commission Registrant, State of Incorporation, I.R.S. Employer File Number Address and Telephone Number Identification No. 1-8809 SCANA Corporation 57-0784499 (a South Carolina Corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000 1-3375 South Carolina Electric & Gas Company 57-0248695 (a South Carolina Corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000 1-11429 Public Service Company of North Carolina, Incorporated 56-2128483 (a South Carolina Corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000 Securities registered pursuant to Section 12(b) of the Act: Each of the following classes or series of securities is registered on the New York Stock Exchange. Title of each class Registrant Common Stock, without par value SCANA Corporation 5% Cumulative Preferred Stock South Carolina Electric & Gas Company par value $50 per share 7.55% Trust Preferred Securities, Series A liquidation value $25 South Carolina Electric & Gas Company per Trust Preferred Security Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrants: (1) have 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 registrants were required to file such reports), and (2) have 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. SCANA Corporation ( ) South Carolina Electric & Gas Company ( ) Public Service Company of North Carolina, Incorporated (X) The aggregate market value of voting stock held by non-affiliates of SCANA Corporation was $2.8 billion at February 28, 2001, based on a price of $27.21. Each of the other registrants is a wholly-owned subsidiary of SCANA Corporation and has no voting stock other than its common stock. A description of registrants' common stock follows: Shares Outstanding Registrant Description of Common Stock at February 28, 2001 ---------- --------------------------- -------------------- SCANA Corporation Without Par Value 104,729,131 South Carolina Electric and Gas Company $4.50 Par Value 40,296,147 Public Service Company of North Carolina,Incorporated Without Par Value 1,000 Documents incorporated by reference: Specified sections of SCANA Corporation's 2001 Proxy Statement, dated March 19, 2001, in connection with its 2001 Annual Meeting of Stockholders, are incorporated by reference in Part III hereof. This combined Form 10-K is separately filed by SCANA Corporation, South Carolina Electric & Gas Company and Public Service Company of North Carolina, Incorporated. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies. Public Service Company of North Carolina, Incorporated meets the conditions set forth in General Instruction I (1) (a) and (b) of Form 10-K and therefore is filing this form with the reduced disclosure format allowed under General Instruction I (2). TABLE OF CONTENTS Page DEFINITIONS.............................................................. 4 PART I Item 1. Business................................................... 5 Item 2. Properties ................................................ 18 Item 3. Legal Proceedings.......................................... 20 Item 4. Submission of Matters to a Vote of Security Holders ....... 20 Corporate Structure ................................................ 21 Executive Officers of SCANA Corporation ............................ 22 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters............................... 23 Item 6. Selected Financial Data.................................... 24 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Item 7A. Quantitative Disclosures About Market Risk Item 8. Financial Statements and Supplementary Data SCANA Corporation.......................................... 25 South Carolina Electric & Gas Company...................... 75 Item 7. Management's Narrative Analysis of Results of Operations Item 7A. Quantitative Disclosures About Market Risk Item 8. Financial Statements and Supplementary Data Public Service Company of North Carolina, Incorporated..... 109 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................................. 138 PART III Item 10. Directors and Executive Officers of the Registrants........ 138 Item 11. Executive Compensation .................................... 142 Item 12. Security Ownership of Certain Beneficial Owners and Management ........................................... 148 Item 13. Certain Relationships and Related Transactions ............ 149 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K ............................................. 150 SIGNATURES............................................................... 154 DEFINITIONS The following abbreviations used in the text have the meanings set forth below unless the context requires otherwise: TERM MEANING AFC...................... Allowance for Funds Used During Construction BTU...................... British Thermal Unit CAA...................... Clean Air Act Amendments of 1990 Circuit Court............ South Carolina Circuit Court 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 DT....................... Dekatherm Energy Marketing......... SCANA Energy Marketing, Inc. 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. Investor Plus Plan....... SCANA Corporation Investor Plus Plan KVA...................... Kilovolt-ampere KW....................... Kilowatt KWH...................... Kilowatt-hour LLC...................... Limited Liability Company LNG...................... Liquefied Natural Gas MCF...................... Thousand Cubic Feet MGP...................... Manufactured Gas Plant Mhz...................... Megahertz MMBTU.................... Million British Thermal Unit MMCF..................... Million Cubic Feet MW....................... Megawatt NEPA..................... National Energy Policy Act of 1992 NCUC..................... North Carolina Utilities Commission NRC...................... United States Nuclear Regulatory Commission PCS...................... Personal Communications Service Pipeline Corporation..... South Carolina Pipeline Corporation PRP...................... Potentially Responsible Party PSC...................... The Public Service Commission of South Carolina PSNC..................... Public Service Company of North Carolina, Incorporated PUHCA.................... Public Utility Holding Company Act of 1935, as amended RTO...................... Regional Transmission Organization SCI...................... SCANA Communications, Inc. 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 Summer Station........... V. C. Summer Nuclear Station Supreme Court............ South Carolina Supreme Court Transco.................. Transcontinental Gas Pipeline Corporation Williams Station......... A. M. Williams Coal-Fired, Electric Generating Station Owned by GENCO WNA Weather Normalization Adjustment PART I ITEM 1. BUSINESS ORGANIZATION SCANA, a South Carolina corporation having general business powers, was incorporated on October 10, 1984, and registered as a public utility holding company under PUHCA on February 10, 2000, concurrent with the completion of its acquisition of PSNC. SCANA holds, directly or indirectly, all of the capital stock of each of its subsidiaries except for the preferred stock of SCE&G, the preferred securities of SCE&G Trust I and 30 percent of an indirect subsidiary. SCANA and its subsidiaries (the Company) had 5,426 full-time, permanent employees as of February 28, 2001 as compared to 5,488 full-time, permanent employees as of February 29, 2000. SCE&G was incorporated under the laws of South Carolina in 1924, and is an operating public utility. SCE&G had 2,412 full-time, permanent employees as of February 28, 2001 as compared to 3,771 full-time, permanent employees as of February 29, 2000. Prior to being acquired by SCANA, PSNC was incorporated under the laws of North Carolina in 1938. Subsequent to its acquisition, PSNC is incorporated under the laws of South Carolina. PSNC is an operating public utility in North Carolina with 653 full-time, permanent employees as of February 28, 2001 as compared to 879 full-time, permanent employees as of February 29, 2000. SEGMENTS OF BUSINESS SCANA neither owns nor operates any physical properties. It has 11 direct, wholly owned subsidiaries that are engaged in the functionally distinct operations described below. It also has investments in two LLCs: one has built and operates a cogeneration facility in Charleston, South Carolina and the other has constructed and operates a lime production facility in Charleston, South Carolina. SCANA also has four other direct, wholly owned subsidiaries that are in liquidation. Information with respect to major segments of business for the years ended December 31, 2000, 1999 and 1998 is contained in Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and the Notes to Consolidated Financial Statements appearing in Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for SCANA (Note 14), SCE&G (Note 13) and PSNC (Note 14). All such information is incorporated herein by reference. Regulated Utilities 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 area of Columbia, 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 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 31 of the 46 counties in South Carolina and covers more than 21,000 square miles. The total population of the counties representing the combined service area is approximately 2.5 million. Predominant industries in the areas served by SCE&G include: synthetic fibers; chemicals; fiberglass; paper and wood; metal fabrication; stone, clay and sand mining and processing; and textile. 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 41 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. Pipeline Corporation also operates a 62-mile six-inch propane pipeline that is owned by Suburban Propane, L.P. of Whippany, New Jersey. On February 10, 2000 SCANA completed its acquisition of PSNC. PSNC is a public utility engaged primarily in transporting, distributing and selling natural gas to approximately 370,000 residential, commercial and industrial customers. PSNC provides service to 25 of its 28 franchised counties covering approximately 11,500 square miles in North Carolina. The industrial customers of PSNC include manufacturers or processors of textiles, chemicals, ceramics and clay products, glass, automotive products, minerals, pharmaceuticals, plastics, metals, electronic equipment, furniture and a variety of food and tobacco products. PSNC, through wholly owned, non-regulated subsidiaries, refuels natural gas vehicles and converts gasoline-fueled vehicles to natural gas. Effective January 1, 2001, PSNC's gas brokering activities were transferred to Energy Marketing. Nonregulated Businesses Energy Marketing markets electricity, natural gas and other light hydrocarbons primarily in the southeast. Energy Marketing, also provides energy-related risk management services to producers and customers. In addition, SCANA Energy, a division of Energy Marketing, markets natural gas to approximately 432,000 customers in Georgia's deregulated natural gas market. SCI owns and operates a 500-mile fiber optics telecommunications network in South Carolina. In addition, SCI provides tower site construction, management and rental services in South Carolina and Georgia. SCI also owns an 800 Mhz radio service network within the state, and in January 2001, signed a letter of intent to sell the network. The sale is expected in April 2001. SCANA Communications Holdings, Inc. (SCH), a Delaware corporation and a wholly owned subsidiary of SCI, has investments in Powertel, Inc., ITC Holding Company, Inc., ITC^DeltaCom, Inc., and Knology, Inc., which are telecommunications services companies in the southeastern United States. On August 28, 2000 SCH announced that Powertel has agreed to be acquired by either Deutsche Telekom AG or VoiceStream Wireless Corporation, as further discussion under "Other" in the Liquidity and Capital Resources section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA. ServiceCare, Inc. is engaged in providing energy-related products and services beyond the energy meter. Its primary businesses are providing homeowners with service contracts on their home appliances and home security services. ServiceCare has announced the sale of its home security business expected to be completed in March 2001. Primesouth, Inc. is engaged in power plant management and maintenance services. SCANA Resources, Inc. conducts energy-related businesses and provides energy-related services. Service Company SCANA Services, Inc. provides administrative, management and other services to the subsidiaries and business units within the Company. COMPETITION For a discussion of the impact of competition, see the Competition section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G. CAPITAL REQUIREMENTS AND FINANCING PROGRAM Capital Requirements The Company's cash requirements arise primarily from SCE&G's and PSNC's operational needs, the Company's construction program, the need to fund the activities or investments of SCANA's nonregulated subsidiaries and payment of dividends. The ability of SCANA'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. SCANA's regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. Depending on customer growth and inflation, and as the regulated subsidiaries continue their ongoing construction programs, it may be necessary to seek increases in rates. The Company's future financial position and results of operations will be affected by the regulated subsidiaries' ability to obtain adequate and timely rate and other regulatory relief, if requested. For a discussion of the impact of various rate matters on the Company's capital requirements, see Regulatory Matters in the Liquidity and Capital Resources section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and the Notes to Consolidated Financial Statements appearing in Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for SCANA (Note 4), SCE&G (Note 3) and PSNC (Note 5). During 2001 the Company is expected to meet its capital requirements principally through internally generated funds (approximately 61 percent, after payment of dividends) and the incurrence of additional short-term and long-term indebtedness. Sales of additional equity securities may also occur. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the next 12 months and for the foreseeable future. The Company's current estimates of its cash requirements for construction and nuclear fuel expenditures, which are subject to continuing review and adjustment, for 2001 and the two-year period 2002-2003 are as follows: -------------------------------------------------------------- ----------------- Type of Facilities 2002-2003 2001 (Millions of Dollars) South Carolina Electric & Gas Company: Electric Plant: Generation $329 $249 Transmission 43 22 Distribution 178 83 Other 17 15 Nuclear Fuel 36 26 Gas 38 20 Common 17 6 Other 1 1 -------------------------------------------------------------- ----------------- Total SCE&G 659 422 PSNC Gas 91 42 Other Companies Combined 193 63 -------------------------------------------------------------- ----------------- Total $943 $527 -------------------------------------------------------------- ----------------- During 2000 SCE&G and GENCO expended approximately $23.2 million and $0.5 million, respectively, as part of a program to extend the operating lives of certain non-nuclear generating facilities. Additional improvements to be made under the program during 2001, included in the table above, are estimated to cost approximately $80.3 million for SCE&G. In addition to the capital requirements for 2001 described above, the Company, SCE&G and PSNC will require approximately $41.5 million, $28.2 million and $4.3 million, respectively, to refund and retire outstanding securities and obligations in 2001. For the years 2002-2005, the Company has an aggregate of $1,705.4 million of long-term debt maturing, which includes an aggregate of $455.2 million for SCE&G, $2.2 million of purchase or sinking fund requirements for SCE&G's preferred stock and $22.5 million for PSNC. SCE&G's long-term debt maturities for the years 2002-2005 include approximately $94.0 million for sinking fund requirements, of which $93.9 million may be satisfied by deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits. SCANA and Westvaco each own a 50 percent interest in Cogen South LLC (Cogen). Cogen was formed to build and operate a cogeneration facility at Westvaco's Kraft Division Paper Mill in North Charleston, South Carolina. The facility began operations in March 1999. On September 10, 1998, the contractor in charge of construction filed suit in Circuit Court seeking approximately $52 million from Cogen, alleging that it incurred construction cost overruns relating to the facility and that the construction contract provides for recovery of these costs. In addition to Cogen, Westvaco, SCE&G and SCANA were also named as defendants in the suit. SCANA and the other defendants believe the suit is without merit and are mounting an appropriate defense. SCANA and SCE&G do not believe that the resolution of this issue will have a material impact on their results of operations, cash flows or financial position. On October 15, 1999 FERC notified SCE&G of its agreement with SCE&G's plan to reinforce Lake Murray Dam in order to maintain the lake in case of an extreme earthquake. SCE&G and FERC have been discussing possible reinforcement alternatives for the dam over the past several years as part of SCE&G's ongoing hydroelectric operating license with FERC. Until discussions are concluded, it is not possible to finalize the cost of the project; however, it is possible that the cost could range up to $250 million. Although any costs incurred by SCE&G are expected to be recoverable through electric rates, SCE&G also is exploring alternative sources of funding. The project is expected to be completed in 2004. On September 21, 1999 SCE&G announced a $256 million gas turbine generator project in Aiken County, South Carolina. Two combined-cycle turbines will burn natural gas to produce 300 megawatts of new electric generation and use exhaust heat to replace coal-fired steam that powers two existing 75 megawatt turbines at the Urquhart Generating Station. The turbine project is scheduled to be completed by June 2002. On October 7, 2000 Summer Station was removed from service for a planned maintenance and refueling outage scheduled to last 38 1/2 days. During initial inspection activities, plant personnel discovered a small leak coming from a hole in a weld in a primary coolant system pipe. SCE&G performed extensive ultrasonic testing of similar welds in the cooling system, which confirmed that the problem was limited to this single weld. A root cause analysis determined that the cause of the crack was primary water stress corrosion cracking. The repair involved cutting out a twelve-inch long spool of the pipe, which included the entire weld, and installing a new spool piece. Repairs have been completed and the integrity of the new welds have been verified through extensive testing. The plant was returned to service in March 2001. The NRC was closely involved throughout this process and approved SCE&G's actions to repair the crack, as well as the restart schedule. SCE&G will continue to monitor primary coolant system pipes during the next outage, scheduled for Spring of 2002. SCE&G recorded a pretax charge of approximately $6 million in the fourth quarter of 2000 to expense repair costs to date. Additional costs that may be recorded in the first quarter of 2001 are not expected to be material. The cost of replacement power is expected to be recovered through SCE&G's electric fuel adjustment clause. In January 2001 SCE&G's 385 megawatt coal-fired Cope Generating Station was taken out of service due to an electrical ground in the generator. The unit is expected to be returned to service in Spring 2001. The cost of replacement power is expected to be recovered through SCE&G's fuel adjustment clause. Financing Program SCANA and PSNC each have in effect a medium-term note program for the issuance from time to time of unsecured medium-term debt securities. At December 31, 2000 SCANA had registered with the SEC and available for issuance $1 billion under its program, the proceeds of which may be used to refinance indebtedness incurred in connection with the acquisition of PSNC, to fund additional business activities in nonutility subsidiaries, to reduce short-term debt or for general corporate purposes. 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 18 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, 2000 the Bond Ratio was 6.43. The Old Mortgage allows the issuance of additional Class A Bonds to an additional principal amount equal to (i) 70 percent of unfunded net property additions (which unfunded net property additions totaled approximately $1,452 million at December 31, 2000), (ii) retirements of Class A Bonds (which retirement credits totaled $68.4 million at December 31, 2000), and (iii) cash on deposit with the Trustee. SCE&G is subject to a bond indenture dated April 1, 1993 (New Mortgage) covering substantially all of its electric properties under which its future mortgage-backed debt (New Bonds) will be issued. New Bonds are issued under the New Mortgage on the basis of a like principal amount of Class A Bonds issued under the Old Mortgage which have been deposited with the Trustee of the New Mortgage (of which $665 million were available for such purpose at December 31, 2000). 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, 2000 the New Bond Ratio was 6.34. The following additional financing transactions have occurred since January 1, 2000: o On February 8, 2000 the Company issued $400 million of two-year floating rate notes maturing February 8, 2002. The interest rate on the notes is reset quarterly based on three-month LIBOR plus 50 basis points. The proceeds from these privately sold notes were used to consummate SCANA's acquisition of PSNC. On February 10, 2000 SCANA borrowed $300 million for a three-year term under a credit agreement with several banks. The interest rate is reset every one, two, three or six months and is based on LIBOR plus 100 basis points. These funds also were used to consummate SCANA's acquisition of PSNC. o On June 14, 2000 SCE&G issued $150 million of First Mortgage Bonds having an annual interest rate of 7.50 percent and maturing on June 15, 2005. The proceeds from the sale of these bonds were used to pay the maturity of SCE&G's $100 million First Mortgage Bonds due June 15, 2000, to reduce short-term debt and for general corporate purposes. o On July 13, 2000 SCANA issued $300 million two-year floating rate notes maturing on July 15, 2002. The interest rate is reset quarterly based on three-month LIBOR plus 65 basis points. Proceeds from the debt were used to repay medium-term notes totaling $170 million, to reduce short-term debt and for general corporate purposes. o On January 24, 2001 SCANA issued $202 million two-year floating rate notes maturing on January 24, 2003. The interest rate is reset quarterly based on three-month LIBOR plus 110 basis points. Proceeds from the debt were used to reduce short-term debt and for general corporate purposes. o On January 24, 2001 SCE&G issued $150 million First Mortgage Bonds having an annual interest rate of 6.70 percent and maturing on February 1, 2011. The proceeds from the sale of these bonds were used to reduce short-term debt and for general corporate purposes. o On February 16, 2001 PSNC issued $150 million of medium-term notes having an annual interest rate of 6.625 percent and maturing on February 15, 2011. These funds were used to reduce short-term debt and for general corporate purposes. The Company's electric and natural gas businesses are seasonal in nature, with the primary demand for electricity being experienced during summer and winter and the primary demand for natural gas being experienced during winter. As a result of the significant increase during the latter half of 2000 in the cost to the Company of natural gas and the colder than normal weather experienced in December, the Company experienced significant increases in its working capital requirements, contributing to the need for the financings by SCANA and PSNC in early 2001 described above. 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 ten percent of the aggregate principal amount of all of SCE&G's secured indebtedness and capital and surplus; however, no such consent is 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. FERC has authorized SCE&G to issue up to $250 million of unsecured promissory notes or commercial paper with maturity dates of 12 months or less, but not later than December 31, 2002. GENCO has not sought such authorization. The SEC order authorizing the Company to register as a public utility holding company under PUHCA imposes various limits during the three years ending February 11, 2003 (the Authorization Period) on SCANA's, SCE&G's and PSNC's ability to issue long- and short-term debt. The order, as amended, requires SCANA, SCE&G and PSNC to maintain common equity of at least 30 percent of their consolidated capitalization. SCANA's issuance of capital securities is limited to $2.385 billion, including securities issued to repay acquisition debt financing. SCANA's short-term borrowings outstanding are limited to $450 million. SCE&G and PSNC may issue commercial paper and establish bank lines of credit for $300 million and $200 million, respectively. In addition, PSNC requires SEC approval under PUHCA prior to issuing long-term debt. SCANA plans to request such approval for PSNC in 2001. At December 31, 2000 SCE&G had $250 million of unused authorized lines of credit which consist of a credit agreement for a maximum of $250 million to support the issuance of commercial paper. SCE&G's commercial paper outstanding at December 31, 2000 and 1999 was $117.5 million and $143.1 million, respectively. In addition, Fuel Company has a credit agreement for a maximum of $125 million with the full amount available at December 31, 2000. The credit agreement supports the issuance of short-term commercial paper for the financing of nuclear and fossil fuels and sulfur dioxide emission allowances. Fuel Company commercial paper outstanding at December 31, 2000 was $70.2 million. This commercial paper and amounts outstanding under the revolving credit agreement, if any, are guaranteed by SCE&G. At December 31, 2000 PSNC had $125 million authorized lines of credit which consist of a credit agreement for a maximum of $125 million to support the issuance of commercial paper. Unused lines of credit at December 31, 2000 totaled $125 million. PSNC's commercial paper outstanding on December 31, 2000 was $125 million. SCE&G's Restated Articles of Incorporation prohibit issuance of additional shares of preferred stock without the 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, 2000 the Preferred Stock Ratio was 2.09. As a result of SCANA's acquisition of PSNC on February 10, 2000, PSNC shareholders were paid $212 million in cash and 17.4 million shares of SCANA common stock valued at approximately $488 million. In connection with this transaction, certain SCANA shareholders were paid $488 million in cash for 16.3 million shares of SCANA common stock. During 2000, shares for the SPSP and the Investor Plus Plan were purchased on the open market. The Company's ratios of earnings to fixed charges (SEC method) were 2.57, 2.98, 3.67, 3.64 and 3.60 for the years ended December 31, 2000, 1999, 1998, 1997 and 1996, respectively. For SCE&G these ratios were 4.20, 3.71, 4.40, 3.85 and 3.80 for the same periods. For PSNC these ratios were 2.97 for the year ended December 31, 2000 and 3.24, 3.23, 3.44 and 3.62 for the fiscal years ended September 30, 1999, 1998, 1997 and 1996, respectively. ELECTRIC OPERATIONS Electric Sales In 2000 residential sales of electricity accounted for 40% of electric sales revenues; commercial sales 30%; industrial sales 19%; sales for resale 3%; and all other 8%. The Company's KWH sales by classification, excluding volumes attributable to the cumulative effect of accounting change, for the years ended December 31, 2000 and 1999 are presented below: Sales KWH (Millions) -------------------------------------------------------------------------------- CLASSIFICATION 2000 1999 % CHANGE -------------------------------------------------------------------------------- Residential 6,665 6,269 6% Commercial 6,305 5,950 6% Industrial 6,665 6,140 9% Sales for resale 1,222 1,189 3% Other 553 518 7% ---------------------------------------------------------------- Total Territorial 21,410 20,066 7% Negotiated Market Sales Tariff 1,942 1,678 16% ================================================================ Total 23,352 21,744 7% ================================================================ Sales for resale includes electricity furnished for resale to two municipalities and two electric cooperatives. Sales under the Negotiated Market Sales Tariff during 2000 include sales to 36 investor-owned utilities and registered marketers, seven electric cooperatives, two municipalities and four federal/state electric agencies. During 1999 sales under the Negotiated Market Sales Tariff included sales to 32 investor-owned utilities and registered marketers, seven electric cooperatives, two municipalities and four federal/state electric agencies. The electric sales volume from residential sales increased for 2000 primarily as a result of colder weather. During 2000 the Company recorded a net increase of 13,701 customers, increasing its total customers to 537,253. The all-time peak demand of 4,211 MW was set on July 20, 2000. Electric Interconnections SCE&G purchases all of the electric generation of Williams Station, owned by GENCO, under a Unit Power Sales Agreement which has been approved by FERC. Williams Station has a generating capacity of 580 MW. SCE&G's transmission system is part of the interconnected grid extending over a large part of the southern and eastern portions of the nation. SCE&G, Virginia Power Company, Duke Power Company, Carolina Power & Light Company, Yadkin, Incorporated and South Carolina Public Service Authority (Santee Cooper) are members of the Virginia-Carolinas Reliability Group, one of several geographic divisions within the Southeastern Electric Reliability Council. This Council 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 the Southeastern Power Administration's Clark Hill Project. On February 9, 2000 the FERC issued FERC Order 2000. The Order requires utilities which operate electric transmission systems to submit plans for the possible formation of an RTO. On October 16, 2000 the Company and two other southeastern electric utilities filed a joint request with FERC to establish GridSouth Transco, LLC (GridSouth). When operational, GridSouth will function as an independent transmission company. Initially, the three utilities will continue to own their respective transmission networks, while GridSouth will provide planning and operational oversight of the electric transmission grid. FERC gave provisional approval to GridSouth in March 2001. GridSouth is expected to be operational by December 2001. 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 1998-2000. 2000 1999 1998 ---- ---- ---- Nuclear: Per million BTU $.46 $.46 $.46 Coal: SCE&G Per ton $37.10 $39.37 $38.19 Per million BTU 1.48 1.57 1.50 GENCO Per ton $38.98 $41.46 $41.67 Per million BTU 1.51 1.61 1.63 Weighted Average Cost of All Fuels: Per million BTU $1.31 $1.32 $1.26 Fuel Supply The following table shows the sources and approximate percentages of the Company's total KWH generation by each category of fuel for the years 1998-2000 and the estimates for 2001 and 2002. Percent of Total KWH Generated ------------------------------------------------------------- Estimated Actual ---------------------- ------------------------------------ 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- Coal 67% 73% 77% 73% 69% Nuclear 20 20 18 22 25 Hydro 6 5 4 4 5 Natural Gas & Oil 7 2 1 1 1 ========== ============= ==================================== 100% 100% 100% 100% 100% ========== ============= ==================================== Coal is used at all five of SCE&G's fossil fuel-fired plants and GENCO's Williams Station. Unit train deliveries are used at all of these plants. On December 31, 2000 SCE&G had approximately a 37-day supply of coal in inventory and GENCO had approximately a 43-day supply. 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 SCANA's existing contracts. Contract coal is purchased from ten suppliers located in eastern Kentucky, Tennessee, southwest Virginia and West Virginia. Contract commitments, which expire at various times from 2001 through 2009, approximate 6.1 million tons annually, which is 88 percent of total expected coal purchases for 2001. Sulfur restrictions on the contract coal range from 0.75 percent to 1.5 percent. SCE&G is building two combined-cycle turbines that will burn natural gas to produce 300 megawatts of new electric generation and use exhaust heat to replace coal-fired steam that powers two existing 75 megawatt turbines at the Urquhart Generating Station. The turbine project is schedule to be completed by June 2002. The Company believes that SCE&G's and GENCO's operations are in compliance with all existing regulations relating to the discharge of sulfur dioxide and nitrogen oxides. The Company is unaware that any more stringent sulfur content requirements for existing plants are contemplated at the state level by DHEC. SCE&G has adequate supplies of uranium or enriched uranium product under contract to manufacture nuclear fuel for Summer Station through 2005. The following table summarizes all contract commitments for the stages of nuclear fuel assemblies: Remaining Expiration Commitment Contractor Regions(1) Date Enrichment United States Enrichment Corporation (2) 16-18 2005 Fabrication Westinghouse Electric Corporation 16-21 2009 (1) A region represents approximately one-third to one-half of the nuclear core in the reactor at any one time. Region 15 was loaded in 2001. Region 16 will be loaded in 2002. (2) Contract provisions for the delivery of enriched uranium product encompass supply, conversion and enrichment services. SCE&G has on-site spent nuclear fuel storage capability until at least 2006 and expects to be able to expand its storage capacity to accommodate the spent fuel output for the life of the plant through spent fuel pool reracking, dry cask storage or other technology as it becomes available. In addition, there is sufficient on-site storage capacity over the life of Summer Station to permit storage of the entire reactor core in the event that complete unloading should become desirable or necessary for any reason. (See Nuclear Fuel Disposal under Environmental Matters for information regarding the contract with the DOE for disposal of spent fuel.) On October 7, 2000 Summer Station was removed from service for a planned maintenance and refueling outage. See preceding discussion of this matter on page 8. Decommissioning For information regarding the decommissioning of Summer Station, see Note 1H, Nuclear Decommissioning, of the Notes to Consolidated Financial Statements appearing in Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for SCANA and SCE&G. GAS OPERATIONS Gas Sales - Regulated In 2000 the Company's residential sales accounted for 38% of gas sales revenues; commercial sales 22%; industrial sales 28%; sales for resale 8%; and other 4%. During the same period, SCE&G's residential sales accounted for 41% of gas sales revenues; commercial sales 32%; and industrial sales 27%. Also during the same period, PSNC's residential sales accounted for 64% of gas sales revenues; commercial sales 27%; and industrial sales 9%. Dekatherm sales by classification, excluding volumes associated with the cumulative effect of accounting change, for the years ended December 31, 2000 and 1999 are presented below: Sales Dekatherms (000) ---------------------------------------------------------------------------------------------------------------------------- The Company SCE&G PSNC % % % CLASSIFICATION 2000 1999* Change 2000 1999 Change 2000 1999 Change ----------------------- ---------- ------------- ------------ ---------- --------- ---------- -------- --------- ----------- Residential 35,365 11,823 199.1% 12,235 11,823 3.5% 23,130 19,976 15.8% Commercial 25,039 11,790 112.4% 12,076 11,699 3.2% 12,850 11,609 10.7% Industrial 61,662 61,748 (0.1%) 17,129 17,958 (4.6%) 5,307 6,349 (16.4%) Sales for Resale 16,931 15,947 6.2% - - - - - - Transportation gas 31,634 2,252 1,304.7% 2,085 1,975 5.6% 29,372 28,750 2.2% -------- ---------- -- ----- ------- ------ ------ Total 170,631 103,560 64.8% 43,525 43,455 0.2% 70,659 66,684 6.0% ======================= ========== ============= ============ ========== ========= ========== ======== ========= =========== *SCANA acquired PSNC effective January 1, 2000 for accounting purposes. Therefore, the Company's 1999 sales do not include PSNC. The Company's and SCE&G's gas sales volume increased for 2000 primarily as a result of customer growth. The Company obtained 354,763 customers when it acquired PSNC. In addition, during 2000 the Company recorded a net increase of 21,798 customers, increasing its total customers to 637,017. SCE&G recorded a net increase of 6,103 gas customers, increasing its total customers to 266,348. PSNC recorded a net increase of 15,148 customers, increasing its total customers to 370,181. The demand for gas is affected by the weather, the price relationship between gas and alternate fuels and other factors. Pipeline Corporation, operating wholly within the State of South Carolina, provides natural gas utility and transportation services for its customers, and supplies natural gas to SCE&G and other wholesale purchasers. Pipeline Corporation is developing plans for an interstate natural gas pipeline to ensure adequate supplies to growing gas markets. The anticipated interstate pipeline will require Pipeline Corporation to file an application for approval with FERC and other federal and state agencies. Energy Marketing acquires and sells natural gas in regulated and deregulated markets. Energy Marketing has not supplied natural gas to any affiliate for use in providing regulated gas utility services. 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 Southern Natural (expiring in 2005 and 2006) and Transco (expiring in 2008 and 2017). The daily volume of gas that Pipeline Corporation is entitled to transport under these contracts on a firm basis is 188 MMCF from Southern Natural and 105 MMCF from Transco. Additional natural gas volumes are brought to Pipeline Corporation's system as capacity is available for interruptible transportation. SCE&G, under contract with Pipeline Corporation, is entitled to receive a daily contract demand of 266,495 dekatherms. The contract allows SCE&G to receive amounts in excess of this demand based on availability. During 2000 Pipeline Corporation's average cost per MCF of natural gas purchased for resale, including firm service demand charges, was $4.42 compared to $2.99 during 1999. SCE&G's average cost per MCF was $5.35 and $3.73 during 2000 and 1999, respectively. Pipeline Corporation has engaged in hedging activities on the New York Mercantile Exchange (NYMEX) of its gas supply pursuant to a limited program authorized and monitored by the PSC. Any gains or losses associated with that hedging activity are accounted for in Pipeline Corporation's purchased gas adjustment clause and, therefore, have no impact on net income. To meet the requirements of its high priority natural gas customers during periods of maximum demand, Pipeline Corporation supplements its supplies of natural gas from two LNG plants. The LNG plants are capable of storing the liquefied equivalent of 1,880 MMCF of natural gas. Approximately 1,192 MMCF of gas were in storage at December 31, 2000. On peak days the LNG plants can regasify up to 150 MMCF per day. Additionally, Pipeline Corporation had contracted for 6,447 MMCF of natural gas storage space. Approximately 3,713 MMCF of gas were in storage on December 31, 2000. PSNC Energy 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 reservation charge. The gas is brought to North Carolina through transportation agreements with Transco and Dominion Gas Transmission with expiration dates ranging through 2016. The daily volume of gas that PSNC Energy is entitled to transport under these contracts on a firm basis is 259,894 dekatherms from Transco and 30,331 dekatherms from Dominion Gas Transmission. PSNC Energy has submitted non-binding nominations for firm transportation service on three proposed pipeline projects to meet incremental capacity requirements beginning in 2003. During 2000 PSNC Energy's average cost per dekatherm of natural gas purchased for resale, including firm service demand charges, was $5.63 compared to $3.71 during 1999. To meet the requirements of its high priority natural gas customers during periods of maximum demand, PSNC Energy supplements its supplies of natural gas with underground natural gas storage services and liquefied natural gas (LNG) peaking services. Underground natural gas storage service agreements with Dominion Gas Transmission, Columbia Gas Transmission and Transco provide for storage capacity of approximately 8,657 MMCF. In addition, PSNC Energy's own LNG facility is capable of storing the liquefied equivalent of 1,000 MMCF of natural gas with daily regasification capability of 106 MMCF. Approximately 835 MMCF were in storage at December 31, 2000. LNG storage service agreements with Transco, Cove Point LNG and Pine Needle LNG provide for approximately 1,266 MMCF of storage space. At December 31, 2000 approximately 869 MMCF were stored in these three facilities. The Company believes that supplies under long-term contract and supplies available for spot market purchase are adequate to meet existing customer demands and to accommodate growth. Curtailment Plans The PSC has established allocation priorities applicable to the firm and interruptible capacities of Pipeline Corporation. The curtailment plan priorities of Pipeline Corporation apply to the resale distribution customers of Pipeline Corporation, including SCE&G. Gas Marketing - Nonregulated Energy Marketing markets natural gas and provides energy-related risk management services to producers and consumers. Energy Marketing is also a power marketer, which allows it to buy and sell large blocks of electric capacity in wholesale markets. In addition, SCANA Energy, a division of Energy Marketing, markets natural gas to approximately 432,000 customers in Georgia's deregulated natural gas market. Although Energy Marketing's activities are primarily focused in the southeast, Energy Marketing has maintained smaller scale operations in the Midwest and in California. While Energy Marketing has from time to time been a customer of the California utilities (PG&E, SoCalEdison and SDG&E), it has not been a supplier to such companies and does not have material direct or indirect credit risk related to them. The Company's Board of Directors has established a Risk Management Committee which is responsible for developing corporate policies and overseeing the management of risk within tolerance parameters approved by the Board. REGULATION General SCANA became a registered public utility holding company under PUHCA on February 10, 2000, concurrent with completion of its acquisition of PSNC. SCANA and its subsidiaries are subject to the jurisdiction of the SEC as to financings, acquisitions and diversifications, affiliate transactions and other matters. 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. Pipeline Corporation is subject to the jurisdiction of the PSC as to gas rates, service, accounting and other matters. PSNC is subject to the jurisdiction of the NCUC as to gas rates, issuance of securities (other than notes with a maturity of two years or less or renewals of notes over a six-year or shorter period), service, accounting and other matters. Federal Energy Regulatory Commission SCE&G and GENCO are subject to regulation under the Federal Power Act, administered by FERC and DOE, in the transmission of electric energy in interstate commerce and in the sale of electric energy at wholesale for resale, as well as with respect to licensed hydroelectric projects and certain other matters, including accounting and the issuance of short-term promissory notes. (See Capital Requirements and Financing Program.) SCE&G holds licenses under the Federal Water Power Act or the Federal Power Act with respect to all of its hydroelectric projects. The expiration dates of the licenses covering the projects are as follows: License License Project Expiration Project Expiration Neal Shoals 2036 Saluda 2007 Stevens Creek 2025 Parr Shoals 2020 Columbia 2000 Fairfield Pumped Storage 2020 SCE&G filed an application for a new license for Columbia on June 30, 1998. The application was officially accepted for filing by FERC notice dated December 23, 1999, and is currently in environmental review. The current license for Columbia expired on June 30, 2000; subsequent to that date, FERC issued a temporary operating license to allow SCE&G to continue to operate the project until a new license is issued. At the termination of a license under the Federal Power Act, the United States government may take over the project covered thereby, or FERC may extend the license or issue a license to another applicant. If the Federal government takes over a project or FERC issues a license to another applicant, the original licensee is entitled to be paid its net investment in the project, not to exceed fair value, plus severance damages. For a discussion of SCE&G's agreement with FERC related to reinforcing the Lake Murray Dam (related to the Saluda hydroelectric project), see previous discussion under Capital Requirements and see Liquidity and Capital Resources in Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G. Nuclear Regulatory Commission SCE&G is subject to regulation by the NRC with respect to the ownership, operation and decommissioning of Summer Station. The NRC's jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety, antitrust considerations and environmental impact. In addition, the Federal Emergency Management Agency is responsible for the review, in conjunction with the NRC, of certain aspects of emergency planning relating to the operation of nuclear plants. National Energy Policy Act of 1992 and FERC Orders No. 636, 888 and 2000 The Company's regulated business operations were impacted by the NEPA and FERC Orders No. 636, 888 and 2000. NEPA was designed to create a more competitive wholesale power supply market by creating "exempt wholesale generators" and by potentially requiring utilities owning transmission facilities to provide transmission access to wholesalers. Order No. 636 was intended to deregulate the markets for interstate sales of natural gas by requiring that pipelines provide transportation services that are equal in quality for all gas suppliers whether the customer purchases gas from the pipeline or another supplier. Orders No. 888 and 2000 require utilities under FERC jurisdiction that own, control or operate transmission lines to file nondiscriminatory open access tariffs that offer to others the same transmission service they provide to themselves and to submit plans for the possible formation of an RTO. The Company believes it will continue to be able to meet successfully the challenges of these altered business climates and does not anticipate there will be any material adverse impact from these Orders on the Company's results of operations, cash flows, financial position or business prospects. RATE MATTERS For a discussion of the impact of various rate matters, see Regulatory Matters in the Liquidity and Capital Resources section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G, and the Notes to Consolidated Financial Statements appearing in Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for SCANA (Note 4), SCE&G (Note 3) and PSNC (Note 5). General SCE&G and PSNC's gas rate schedules for their residential and small commercial customers include a WNA. SCE&G's and PSNC's WNA were approved by the PSC and NCUC, respectively, and are in effect for bills rendered during the period from November 1 through April 30 of each year. In each case the WNA increases tariff rates if weather is warmer than normal and decreases rates if weather is colder than normal. The WNA does not change the seasonality of gas revenues; however, it does reduce fluctuations caused by abnormal weather. 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 annually based on projected fuel costs for the ensuing 12-month period, adjusted for any overcollection or undercollection from the preceding 12-month period. SCE&G has the right to request a formal proceeding at any time should circumstances dictate such a review. In the April 2000 annual review of the fuel cost component of electric rates, the PSC decreased the fuel cost component of the electric rate to 13.30 mills per KWH. For the April 2001 annual review, SCE&G has filed for an increase in the fuel cost component of electric rates to 15.79 mills per KWH. SCE&G's gas rate schedules and contracts include mechanisms that 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 July 2000 the PSC approved SCE&G's request for an out-of-period adjustment to increase the cost of gas component from 54.334 cents per therm to 68.835 cents per therm, effective with the first billing cycle in August 2000. In the October 2000 review the PSC increased the base cost of gas to 78.151 cents per therm. In December 2000 the PSC approved SCE&G's request for an out-of-period adjustment to increase the cost of gas component to 99.340 cents per therm, effective with the first billing cycle in January 2001. In March 2001 the PSC approved SCE&G's request to decrease the cost of gas component to 79.340 cents per therm, effective with the first billing cycle in March 2001. PSNC also operates under two rate provisions in addition to WNA that serve to reduce fluctuations in PSNC's earnings. First, its Rider D rate mechanism allows PSNC to recover, in any manner authorized by the NCUC, margin losses on negotiated gas sales. The Rider D rate mechanism also allows PSNC to recover from customers all prudently incurred gas costs, including changes in natural gas prices. Second, PSNC operates with full margin transportation rates. These rates allow PSNC to earn the same margin on gas delivered to customers regardless of whether the gas is sold, or only transported, by PSNC to the customer. PSNC's rates are established using a base cost of gas approved by the NCUC, which may be modified periodically to reflect changes in the market price of natural gas and changes in the rates charged by PSNC's pipeline transporters. PSNC may file revised tariffs with the NCUC coincident with these changes or it may track the changes in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC's gas purchasing practices annually. ENVIRONMENTAL MATTERS General Federal and state authorities have imposed environmental regulations and standards relating primarily to air emissions, wastewater discharges and solid, toxic and hazardous waste management. Developments in these areas may require that equipment and facilities be modified, supplemented or replaced. The ultimate effect of these regulations and standards upon existing and proposed operations cannot be forecast. For a more complete discussion of how these regulations and standards impact the Company and SCE&G, see the Environmental Matters section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G. Capital Expenditures In the years 1998 through 2000, the Company's capital expenditures for environmental control amounted to approximately $98.4 million (including approximately $88.1 million for SCE&G). This was in addition to expenditures included in "Other operation and maintenance" expenses, which were approximately $19.6 million, $18.2 million, and $18.8 million during 2000, 1999 and 1998, respectively (including approximately $16.6 million, $15.0 million and $16.2 million for SCE&G during 2000, 1999 and 1998, respectively). It is not possible to estimate all future costs for environmental purposes, but forecasts for capitalized environmental expenditures for the Company are $23.3 million for 2001 and $192.8 million for the four-year period 2002 through 2005 (including $22.8 million for 2001 and $129.4 million for the four-year period 2002 through 2005 for SCE&G). These expenditures are included in the Company's and SCE&G's construction program. In October 1998 the EPA issued a final rule requiring 22 states, including South Carolina, to modify their state implementation plans (SIP) to address the issue of NOx pollution. On May 25, 1999 a federal appeals court delayed indefinitely the implementation of the rule. On March 3, 2000 the court affirmed the EPA's NOx rule for the affected states. South Carolina was subsequently ordered to amend its SIP to achieve significant NOx reductions. South Carolina failed to submit a revised SIP as required under the CAA, and the EPA has issued official notice to South Carolina (and a number of other states) to comply. While not final, South Carolina has proposed NOx reductions that would require the Company to install pollution control equipment. Because DHEC had not amended its SIP as of December 31, 2000 to set out or allocate any NOx reductions, it is not possible to estimate what, if any, capital expenditures will be required to comply with any potential mandated reductions. Nuclear Fuel Disposal The Nuclear Waste Policy Act of 1982 required that the United States government make available by 1998 a permanent repository for high-level radioactive waste and spent nuclear fuel and imposes a fee of 1.0 mil per KWH of net nuclear generation after April 7, 1983. Payments, which began in 1983, are subject to change and will extend through the operating life of 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 nuclear fuel storage capability until at least 2006 and expects to be able to expand its storage capacity to accommodate the spent nuclear fuel output for the life of the plant through spent fuel pool reracking, dry cask storage or other technology as it becomes available. The Act also imposes on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. OTHER MATTERS With regard to SCE&G's insurance coverage for Summer Station, reference is made to the Notes to Consolidated Financial Statements (Note 13B for the Company and Note 12B for SCE&G), which are incorporated herein by reference. For a description of the Company's investments in various telecommunications companies, see Other in the Liquidity and Capital Resources section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA. ITEM 2. PROPERTIES SCANA owns no significant property other than the capital stock of each of its subsidiaries. It holds, directly or indirectly, all of the capital stock of each of its subsidiaries except for the preferred stock of SCE&G, the preferred securities of SCE&G Trust I and 30 percent of an indirect subsidiary. It also has investments in two LLCs: one operates a cogeneration facility in Charleston, South Carolina and the other operates a lime production facility in Charleston, South Carolina. 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-SEGMENTS OF BUSINESS-Nonregulated Businesses. ELECTRIC Information on electric generating facilities, all of which are owned by SCE&G except as noted, is as follows: Net Generating Present Year Capacity Facility Fuel Capability Location In-Service (Summer Rating) (KW) Steam ----- Urquhar(1) Coal/Gas Beech Island, SC 1953 250,000 McMeekin Coal/Gas Irmo, SC 1958 252,000 Canadys Coal/Gas Canadys, SC 1962 420,000 Wateree Coal Eastover, SC 1970 700,000 Williams(2) Coal Goose Creek, SC 1973 615,000 Summer(3) Nuclear Parr, SC 1984 635,000 D-Area(4) Coal DOE Savannah River Site, SC 1995 38,000 Cope Coal Cope, SC 1996 417,000 Cogen South * Charleston, SC 1999 65,000 Gas Turbines ------------ Burton Gas/Oil Burton, SC 1961 28,500 Faber Place Gas Charleston, SC 1961 9,500 Hardeeville Oil Hardeeville, SC 1968 14,000 Urquhart Gas/Oil Beech Island, SC 1969 38,000 Coit Gas/Oil Columbia, SC 1969 30,000 Parr Gas/Oil Parr, SC 1970 60,000 Williams Gas/Oil Goose Creek, SC 1972 49,000 Hagood Gas/Oil Charleston, SC 1991 95,000 Urquhart #4 Gas/Oil Beech Island, SC 1999 48,000 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 536,000 ---------- 4,544,000 (1) On September 21, 1999 SCE&G announced a $256 million gas turbine generator project in Aiken County, South Carolina. Two combined-cycle turbines will burn natural gas to produce 300 megawatts of new electric generation and use exhaust heat to replace coal-fired steam that powers two existing 75 megawatt turbines at the Urquhart Generating Station. The turbine project is scheduled to be completed by June 2002. (2) The steam unit at Williams Station is owned by GENCO. (3) Represents SCE&G's two-thirds portion of the Summer Station. (4) This plant is leased from the DOE and is dedicated to DOE's Savannah River Site steam needs. "Net Generating Capability" for this plant is expected average hourly output. The lease expires on October 1, 2005. * SCE&G receives shaft horse power from Cogen South, LLC to operate SCE&G's generator. Cogen South, LLC is owned 50 percent by SCANA and 50 percent by Westvaco. SCE&G owns 450 substations having an aggregate transformer capacity of 22,673,443 KVA. The transmission system consists of 3,166 miles of lines and the distribution system consists of 16,778 pole miles of overhead lines and 3,836 trench miles of underground lines. GAS Natural Gas SCE&G's gas system consists of approximately 12,596 miles of distribution mains and related service facilities. SCE&G also has propane air peak shaving facilities which can supplement the supply of natural gas by gasifying propane to yield the equivalent of 73 MMCF per day. These facilities can store the equivalent of 392 MMCF of natural gas. Pipeline Corporation's gas system consists of approximately 1,947 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 and the other in Salley, South Carolina. The Charleston facility can liquefy up to 6 MMCF per day and store the liquefied equivalent of 980 MMCF of natural gas. The Salley facility can store the liquefied equivalent of 900 MMCF of natural gas and has no liquefying capabilities. On peak days, the Charleston facility can regasify up to 60 MMCF per day and the Salley facility can regasify up to 90 MMCF. PSNC's gas system consists of approximately 785 miles of transmission pipeline of up to 24 inches in diameter that connect its distribution systems with Transco. PSNC's distribution system consists of approximately 7,049 miles of distribution mains and related service facilities. PSNC also owns, through a wholly owned subsidiary, 33.21 percent of Cardinal Pipeline Company, LLC, which owns a 105-mile transmission pipeline. In addition, PSNC owns, through a wholly owned subsidiary, 17 percent of Pine Needle LNG Company, LLC. Pine Needle owns and operates a liquefaction, storage and regasification facility. TRANSIT SCE&G owns 40 motor coaches used in the operation of the Columbia transit system. The Columbia system is comprised of 17 routes covering 177 miles. SCE&G intends to dispose of its investment in the Columbia transit system as soon as practicable. Management is uncertain as to what the costs associated with the disposition of the transit system will be. ITEM 3. LEGAL PROCEEDINGS For information regarding legal proceedings, see Item 1, BUSINESS RATE MATTERS (the Company, SCE&G and PSNC), Environmental Matters in the Liquidity and Capital Resources section of Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (the Company and SCE&G), and Notes to Consolidated Financial Statements appearing in Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Note 13C and 13E for the Company, Note 12C and 12E for SCE&G and Note 12 for PSNC). ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not Applicable CORPORATE STRUCTURE SCANA CORPORATION A holding company, owning the direct, wholly owned subsidiaries listed below SOUTH CAROLINA ELECTRIC & GAS COMPANY SCANA COMMUNICATIONS, INC. ------------------------- -------------------------- Generates and sells electricity and gas Provides fiber optic telecommunications to wholesale and retail customers, in South Carolina, tower construction, purchases, sells and transports management and rental services for natural gas at retail and provides wireless providers and, through a public tansit service in Columbia. subsidiary, invests in telecommunications companies. SCANA ENERGY MARKETING, INC. SOUTH CAROLINA GENERATING Markets electricity, natural gas and COMPANY, INC. other light hydrocarbons primarily in Owns and operates Williams Station and the southeast. Provides energy-related risk sells electricity to SCE&G. management services to producers and customers. Through its SCANA Energy division, markets SOUTH CAROLINA FUEL natural gas in Georgia's deregulated retail natural COMPANY, INC. gas market. Acquires, owns and provides financing for SCE&G's nuclear fuel, fossil fuel SERVICECARE, INC. and sulfur dioxide emission allowances. Provides energy-related products and service contracts on home appliances. SOUTH CAROLINA PIPELINE CORPORATION PRIMESOUTH, INC. Purchases, sells and transports natural Engages in power plant management and gas to wholesale and direct industrial maintenance services. customers. Owns and operates two LNG plants for the liquefaction, storage and SCANA RESOURCES, INC. regasification of natural gas. Conducts energy-related businesses and provides energy-related services. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED SCANA SERVICES, INC. Purchases, sells and transports natural gas Provides administrative, management and other to retail customers, markets natural gas, services to the subsidiaries and business units refuels natural gas vehicles and within SCANA Corporation. converts gasoline-fueled vehicles to natural gas. Each of the above listed companies is organized and incorporated under the laws of the State of South Carolina. SCANA also owns four additional companies that are in liquidation. EXECUTIVE OFFICERS OF SCANA CORPORATION 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 a resignation is submitted, or unless the Board of Directors shall otherwise determine. Positions Held During Name Age Past Five Years Dates W. B. Timmerman 54 Chairman of the Board and Chief Executive Officer 1997-present Chief Operating Officer 1996-1997 President *-present President, SCI 1996-1997 Chief Financial Officer and Controller *-1996 H. T. Arthur 55 Senior Vice President and General Counsel 1998-present Vice President and General Counsel 1996-1998 Vice President and General Counsel, Pipeline Corporation *-1996 G. J. Bullwinkel 52 Senior Vice President, Governmental Affairs and Economic Development 1999-present President, SCI 1997-present Senior Vice President - Retail Electric, SCE&G *-1999 A. H. Gibbes 54 President and Chief Operating Officer, Pipeline Corporation 1996-present Senior Vice President and General Counsel *-1996 President and Treasurer, SCANA Development Corp. *-present D. C. Harris 48 Senior Vice President of Human Resources - SCANA 2000-present Vice President Human Resources, Austin Quality Foods, Inc., Cary, NC *-2000 N. O. Lorick 50 President and Chief Operating Officer, SCE&G 2000-present Vice President of Fossil and Hydro Operations *-2000 K. B. Marsh 45 Senior Vice President - Finance and Chief Financial Officer 2000-present Senior Vice President - Finance, Chief Financial Officer and Controller 1998-2000 Vice President - Finance, Chief Financial Officer and Controller 1996-1998 Vice President - Finance, Treasurer and Secretary *-1996 A. M. Milligan 41 Senior Vice President - Marketing 1998-present Director of Consumer Credit Marketing, Barnett Bank, N. A., FL 1996-1998 Senior Vice President - Marketing, Barnett Card Services, FL *-1996 C. E. Zeigler, Jr. 54 President and Chief Operating Officer of PSNC 2000-present Chairman, President and Chief Executive Officer *-2000 of PSNC (prior to acquisition) S. A. Byrne 40 Vice President Nuclear Operations 2000-present General Manager Nuclear Plant Operations *-2000 M. R. Cannon 50 Controller, SCANA and all subsidiaries (excluding SEMI) 2000-present Treasurer, SCANA and SCE&G *-2000 * Indicates position held at least since March 1, 1996. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS COMMON STOCK INFORMATION - SCANA Corporation -------------------- ---------------------------------------------------- ---------------------------------------------------- 2000 1999 -------------------- ----------- ------------- -------------- ----------- ------------ ------------ ------------- ------------ 4th 1st Qtr. 3rd Qtr. 2nd Qtr. Qtr. 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr. -------------------- ----------- ------------- -------------- ----------- ------------ ------------ ------------- ------------ Price Range: (a) High 31.13 30.94 26.88 29.00 28.31 25.69 26.94 32.56 Low 25.75 24.38 22.81 22.00 23.63 22.81 21.13 21.56 -------------------- ----------- ------------- -------------- ----------- ------------ ------------ ------------- ------------ (a) As reported on the New York Stock Exchange Composite Listing. ------------------------------ -------------------- ------------------- ------------ -------------------- ----------------- Dividends Per Share 2000 1999 ------------------------------ -------------------- ------------------- -------------------- ----------------- ------------ Amount Date Declared Date Paid Amount Date Declared Date Paid ------ ------------- --------- ------ ------------- --------- First Quarter .2875 February 22, 2000 April 1, 2000 .3850 March 9, 1999 April 1, 1999 Second Quarter .2875 April 27, 2000 July 1, 2000 .3850 June 9, 1999 July 1, 1999 Third Quarter .2875 August 16, 2000 October 1, 2000 .2750 September 10,1999 October 1, 1999 Fourth Quarter .2875 October 17, 2000 January 1, 2001 .2750 December 10,1999 January 1,2000 ------------------ ----------- -------------------- ------------------- ------------ -------------------- ----------------- 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, 2001 was 104,729,131. The number of common stockholders of record at February 28, 2001 was 43,245. All of SCE&G and PSNC's common stock is owned by SCANA and has no market. During 2000 and 1999 SCE&G paid $130.8 million and $122.4 million, respectively, in cash dividends to SCANA. During 2000, PSNC paid $19.0 million in cash dividends to SCANA. SECURITIES RATINGS (As of February 28, 2001) SCANA SCE&G PSNC ---------------------- ---------------------------- ---------------------------------------------- -- ---------------------- First and Medium- First Refunding Trust Rating Term Mortgage Mortgage Preferred Preferred Commercial Senior Commercial Agency Notes Bonds Bonds Stock Securities Paper Unsecured Paper ------ ----- ----- ----- ----- ---------- ----- --------- ----- Fitch IBCA, Duff & Phelps A- A+ A+ A A F-1 n/a n/a Moody's A3 A1 A1 a2 a2 P-1 A2 P-1 Standar & A- Poors d A A BBB+ BBB+ A-1 A A-1 --------- ------------ ---------------- ------------- ------------ ------------ --------------- -------------- ------------- Further reference is made to the Notes to Consolidated Financial Statements appearing in Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for SCANA (Note 6), SCE&G (Note 5) and PSNC (Note 7). The Restated Articles of Incorporation of SCE&G and the Indenture underlying its First and Refunding Mortgage Bonds contain provisions that, under certain circumstances, could limit the payment of cash dividends on common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2000 approximately $32.7 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock of SCE&G. ITEM 6. SELECTED FINANCIAL DATA SCANA ------------------------------------------------------ ---------- ----------- ------------ ---------- ---------- --- For the Years Ended December 31, 2000(1) 1999 1998 1997 1996 ------------------------------------------------------ ---------- ----------- ------------ ---------- ---------- --- Statement of Income Data Operating Revenues $3,433 $2,078 $2,106 $1,725 $1,510 Operating Income 554 353 470 425 442 Other Income (Loss) 44 90 19 41 20 Income Before Cumulative Effect of Accounting Change 221 179 223 221 215 Net Income 250 179 223 221 215 Balance Sheet Data Utility Plant, Net $4,949 $3,851 $3,787 $3,648 $3,529 Total Assets 7,420 6,011 5,281 4,932 4,759 Capitalization: Common equity 2,032 2,099 1,746 1,788 1,684 Preferred Stock (Not subject to purchase or sinking funds) 106 106 106 106 26 Preferred Stock (Subject to purchase or sinking funds) 10 11 11 12 43 SCE&G - Obligated Mandatorily Redeemable Preferred Securities of SCE&G's Subsidiary, SCE&G Trust I, Holding Solely $50 million Principal Amount of 7.55% Junior Subordinated Debentures of SCE&G, due 2027 50 50 50 50 - Long-term Debt, net 2,850 1,563 1,623 1,566 1,581 ------------------------------------------------------ ---------- ----------- ------------ ---------- ---------- ====================================================== ========== =========== ============ ========== --- Total Capitalization $5,048 $3,829 $3,536 $3,522 $3,334 ====================================================== ========== =========== ============ ========== ========== --- Common Stock Data Weighted Average Number of Common Shares Outstanding (Millions) 104.5 103.6 105.3 107.1 105.1 Basic and Diluted Earnings Per Share $2.40 $1.73 $2.12 $2.06 $2.05 Dividends Declared Per Share of Common Stock $1.15 $1.32 $1.54 $1.51 $1.47 Other Statistics (2) Electric: Customers (Year-End) 537,253 523,552 517,447 503,905 493,320 Total sales (Million KWH) 23,352 21,744 21,203 18,852 18,905 Residential: Average annual use per customer (KWH) 14,596 14,011 14,481 13,214 14,149 Average annual rate per KWH $.0787 $.0787 $.0801 $.0799 $.0785 Generating capability - Net MW (Year-End) 4,544 4,483 4,387 4,350 4,316 Territorial peak demand - Net MW 4,211 4,158 3,935 3,734 3,698 Regulated Gas: Customers (Year-End) 637,017 260,456 257,051 252,797 248,787 Sales, excluding transportation (Thousand Therms) 1,389,975 1,013,083 1,002,952 945,289 893,170 Residential: Average annual use per customer (Therms) 644 507 521 531 639 Average annual rate per therm $1.08 $.86 $.86 $.86 $.74 Nonregulated Gas: Retail customers (Year-End) 431,814 430,950 78,091 n/a n/a Firm customer deliveries (Thousand Therms) 431,115 229,660 4,692 n/a n/a Interruptible customer deliveries (Thousand Therms) 306,099 188,828 2,167,931 n/a n/a SCE&G ------------------------------------------------------ ---------- ---------- ---------- ---------- ---------- For the Years Ended December 31, 2000 1999 1998 1997 1996 ------------------------------------------------------ ---------- ---------- ---------- ---------- ---------- Statement of Income Data Operating Revenues $1,669 $1,465 $1,450 $1,337 $1,341 Operating Income 457 393 448 387 404 Other Income (Loss) 16 12 9 5 (6) Income Before Cumulative Effect of Accounting Change 231 189 227 195 190 Net Income 253 189 227 195 190 Balance Sheet Data Utility Plant, Net $3,615 $3,501 $3,432 $3,310 $3,197 Total Assets 4,664 4,404 4,246 4,054 3,959 Capitalization: Common equity 1,657 1,558 1,499 1,447 1,413 Preferred Stock (Not subject to purchase or sinking funds) 106 106 106 106 26 Preferred Stock (Subject to purchase or sinking funds) 10 11 11 12 43 SCE&G - Obligated Mandatorily Redeemable Preferred Securities of SCE&G's Subsidiary, SCE&G Trust I, Holding Solely $50 million Principal Amount of 7.55% Junior Subordinated Debentures of SCE&G, due 2027 50 50 50 50 - Long-term Debt, net 1,267 1,121 1,206 1,262 1,277 ------------------------------------------------------ ---------- ---------- ---------- ---------- ---------- ====================================================== ========== ========== ========== ========== ========== Total Capitalization $3,090 $2,846 $2,872 $2,877 $2,759 ====================================================== ========== ========== ========== ========== ========== Common Stock Data Weighted Average Number of Common Shares Outstanding (Millions) n/a n/a n/a n/a n/a Basic and Diluted Earnings Per Share n/a n/a n/a n/a n/a Dividends Declared Per Share of Common Stock n/a n/a n/a n/a n/a Other Statistics (2) Electric: Customers (Year-End) 537,286 523,581 517,472 503,930 493,346 Total sales (Million KWH) 23,353 21,746 21,204 18,853 18,907 Residential: Average annual use per customer (KWH) 14,596 14,011 14,481 13,214 14,149 Average annual rate per KWH $.0787 $.0787 $.0801 $.0799 $.0785 Generating capability - Net MW (Year-End) 3,929 3,883 3,807 3,790 3,756 Territorial peak demand - Net MW 4,216 4,158 3,935 3,734 3,698 Regulated Gas: Customers (Year-End) 266,451 260,348 256,843 252,589 248,497 Sales, excluding transportation (Thousand Therms) 414,405 414, 800 405,249 381,726 387,328 Residential: Average annual use per customer (Therms) 563 507 521 531 639 Average annual rate per therm $.95 $.86 $.86 $.86 $ .74 Nonregulated Gas: Retail customers (Year-End) n/a n/a n/a n/a n/a Firm customer deliveries (Thousand Therms) n/a n/a n/a n/a n/a Interruptible customer deliveries (Thousand Therms) n/a n/a n/a n/a n/a SCANA CORPORATION Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................ 26 Item 7A. Quantitative Disclosures About Market Risk................... 41 Item 8. Financial Statements and Supplementary Data.................. 42 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Statements included in this discussion and analysis (or elsewhere in this annual report) which are not statements of historical fact are intended to be, and are hereby identified as, "forward-looking statements" for purposes of the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following: (1) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) changes in the utility regulatory environment, (3) changes in the economy, especially in areas served by the Company's subsidiaries , (4) the impact of competition from other energy suppliers, (5) growth opportunities for the Company's regulated and diversified subsidiaries, (6) the results of financing efforts, (7) changes in the Company's accounting policies, (8) weather conditions, especially in areas served by the Company's subsidiaries , (9) performance of and marketability of the Company's investments in telecommunications companies, (10) inflation, (11) changes in environmental regulations and (12) the other risks and uncertainties described from time to time in the Company's periodic reports filed with the SEC. The Company disclaims any obligation to update any forward-looking statements. COMPETITION Regulated Electric and Gas Markets Efforts to restructure electric markets at the state level have slowed considerably. Dwindling operating reserves and rolling blackouts in parts of California in January and February 2001 have been widely reported nationwide. These shortages of electricity have been attributed to flawed state restructuring legislation, unplanned generating plant shutdowns and other economic factors. In response, many states that had passed or considered legislation to restructure the electric industry have stopped such efforts or are proceeding more slowly. In South Carolina, electric restructuring efforts also have stalled. The developments unfolding in California, and several unrelated, contentious issues before the General Assembly have combined to make consideration of electric restructuring legislation unlikely in 2001. Legislation or regulatory action at the Federal level, particularly as a part of a larger energy policy initiative, may be considered in 2001. The Company is not able to predict whether any restructuring legislation or regulatory action will be enacted and, if it is, the conditions it will impose on utilities. The Company has taken several steps to prepare for restructuring, including aggressive participation in the newly deregulated natural gas market in Georgia (further discussed at Georgia Retail Gas Market below). In addition, SCANA's electric and gas utility, SCE&G, has undertaken a variety of initiatives aimed at preparing for a restructured electric market. These initiatives include obtaining accelerated recovery of electric regulatory assets, establishing open access transmission tariffs and selling bulk power to wholesale customers at market-based rates. Marketing of services to commercial and industrial customers has also increased significantly, and SCE&G has obtained long term power supply contracts with a significant portion of its industrial customers. The Company believes that these actions, as well as numerous others that have been and will be taken, demonstrate its ability and commitment to succeed in the evolving operating environment. Regulated public utilities are allowed to record as assets some costs that would be expensed by other enterprises. If deregulation or other changes in the regulatory environment occur, the Company may no longer be eligible to apply this accounting treatment and may be required to eliminate such regulatory assets from its balance sheet. Although the potential effects of deregulation cannot be determined at present, discontinuation of the accounting treatment could have a material adverse effect on the Company's results of operations in the period the write-off would be recorded. It is expected that cash flows and the financial position of the Company would not be materially affected by the discontinuation of the accounting treatment. The Company reported approximately $244 million and $75 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities of approximately $140 million and $57 million, respectively, on its balance sheet at December 31, 2000. The Company's generation assets are exposed to considerable financial risks in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, the Company could be required to write down its investment in these assets. The Company cannot predict whether any write-downs will be necessary and, if they are, the extent to which they would adversely affect the Company's results of operations in the period in which they would be recorded. As of December 31, 2000 the Company's net investment in fossil/hydro and nuclear generation assets was $1,332.6 million and $587.2 million, respectively. North Carolina Gas Market On February 10, 2000 SCANA completed its acquisition of Public Service Company of North Carolina, Inc. (PSNC) in a transaction valued at approximately $900 million, including the assumption of debt. The transaction has been accounted for as a purchase. PSNC is operated as a wholly-owned subsidiary of SCANA. As a result of the transaction, SCANA became a registered public utility holding company under PUHCA. Georgia Retail Gas Market SCANA Energy, the retail gas division of Energy Marketing, has been aggressively marketing natural gas to residential and commercial customers in Georgia. SCANA Energy is Georgia's second largest gas marketer, with approximately 432,000 customers at December 31, 2000, or approximately a 30 percent market share. For purposes of comparison, SCANA Energy had approximately 431,000 customers at December 31, 1999 and 78,000 at December 31, 1998. In 2000 SCANA Energy successfully transitioned from start up to ongoing operations and for the year ended December 31, 2000 recognized net earnings of approximately $4.4 million. SCANA Energy's strategy includes the determination of methodologies to serve all customer classes profitably and developing programs that will enhance relationships with those customers and attract similar new customers. In addition SCANA Energy has successfully employed a gas supply hedging strategy and has maintained a price structure that is both competitive and profitable. The level of future revenues and expenditures is dependent on several factors, including SCANA Energy's ability to retain customers and market share, the weather, the margin achieved on gas sales and its ability to find industrial interruptible customers to purchase available capacity. Proposed Interstate Pipeline Pipeline Corporation, a wholly owned subsidiary of the Company, is developing plans for an interstate natural gas pipeline to ensure adequate supplies to growing gas markets. The anticipated interstate pipeline will require Pipeline Corporation to file an application for approval with the FERC and other federal and state agencies. LIQUIDITY AND CAPITAL RESOURCES The Company's cash requirements arise primarily from SCE&G's and PSNC's operational needs, the Company's construction program, the need to fund the activities or investments of SCANA's nonregulated subsidiaries and payment of dividends. The ability of SCANA'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. SCANA'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 continue their ongoing construction programs, it may be 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 and other regulatory relief, if requested. The revised estimated primary cash requirements for 2001 and the actual primary cash requirements for 2000, excluding requirements for fuel liabilities and short-term borrowings, are as follows: (Millions of Dollars) 2001 2000 ------------------------------------------------------------- -------------- Property additions and construction expenditures, net of allowance for funds used during construction $501 $332 Nuclear fuel expenditures 26 29 Investments 25 20 Maturing obligations, redemptions and sinking and purchase fund requirements 14 284 ------------------------------------------------------------- -------------- Total $566 $665 ============================================================= ============== Approximately 39 percent of total cash requirements (after payment of dividends) was provided from internal sources in 2000 as compared to 16 percent in 1999. The Company anticipates that its 2001 cash requirements of $566 million will be met through internally generated funds (approximately 61 percent, after payment of dividends), and the incurrence of additional short-term and long-term indebtedness. Sales of additional equity securities may also occur. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the next 12 months and for the foreseeable future. SCANA and PSNC each have in effect a medium-term note program for the issuance from time to time of unsecured medium-term debt securities. At December 31, 2000 SCANA had registered with the SEC and available for issuance $1 billion under this program, the proceeds of which may be used to refinance indebtedness incurred in connection with the acquisition of PSNC, to fund additional business activities in nonutility subsidiaries, to reduce short-term debt or for general corporate purposes. On February 14, 2001 PSNC registered $150 million of medium-term notes with the SEC. 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 18 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, 2000 the Bond Ratio was 6.43. The Old Mortgage allows the issuance of additional Class A Bonds to an additional principal amount equal to (i) 70 percent of unfunded net property additions (which unfunded net property additions totaled approximately $1,452 million at December 31, 2000), (ii) retirements of Class A Bonds (which retirement credits totaled $68.4 million at December 31, 2000), and (iii) cash on deposit with the Trustee. SCE&G is subject to a bond indenture dated April 1, 1993 (New Mortgage) covering substantially all of its electric properties under which its future mortgage-backed debt (New Bonds) will be issued. New Bonds are issued under the New Mortgage on the basis of a like principal amount of Class A Bonds issued under the Old Mortgage which have been deposited with the Trustee of the New Mortgage (of which $665 million were available for such purpose at December 31, 2000). 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, 2000 the New Bond Ratio was 6.34. The following additional financing transactions have occurred since January 1, 2000: o On February 8, 2000 the Company issued $400 million of two-year floating rate notes maturing February 8, 2002. The interest rate on the notes is reset quarterly based on three-month LIBOR plus 50 basis points. The proceeds from these privately sold notes were used to consummate SCANA's acquisition of PSNC. On February 10, 2000 SCANA borrowed $300 million for a three-year term under a credit agreement with several banks. The interest rate is reset every one, two, three or six months and is based on LIBOR plus 100 basis points. These funds also were used to consummate SCANA's acquisition of PSNC. o On June 14, 2000 SCE&G issued $150 million of First Mortgage Bonds having an annual interest rate of 7.50 percent and maturing on June 15, 2005. The proceeds from the sale of these bonds were used to pay the maturity of SCE&G's $100 million First Mortgage Bonds due June 15, 2000, to reduce short-term debt and for general corporate purposes. o On July 13, 2000 SCANA issued $300 million two-year floating rate notes maturing on July 15, 2002. The interest rate is reset quarterly based on three-month LIBOR plus 65 basis points. Proceeds from the debt were used to repay medium-term notes totaling $170 million, to reduce short-term debt and for general corporate purposes. o On January 24, 2001 SCANA issued $202 million two-year floating rate notes maturing on January 24, 2003. The interest rate is reset quarterly based on three-month LIBOR plus 110 basis points. Proceeds from the debt were used to reduce short-term debt and for general corporate purposes. o On January 24, 2001 SCE&G issued $150 million First Mortgage Bonds having an annual interest rate of 6.70 percent and maturing on February 1, 2011. The proceeds from the sale of these bonds were used to reduce short-term debt and for general corporate purposes. o On February 16, 2001 PSNC issued $150 million of medium-term notes having an annual interest rate of 6.625 percent and maturing on February 15, 2011. These funds were used to reduce short-term debt and for general corporate purposes. The Company's electric and natural gas businesses are seasonal in nature, with the primary demand for electricity being experienced during summer and winter and the primary demand for natural gas being experienced during winter. As a result of the significant increase during the latter half of 2000 in the cost to the Company of natural gas and the colder than normal weather experienced in December, the Company experienced significant increases in its working capital requirements, contributing to the need for the financings by SCANA and PSNC in early 2001 described above. 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 ten percent of the aggregate principal amount of all of SCE&G's secured indebtedness and capital and surplus; however, no such consent is 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. FERC has authorized SCE&G to issue up to $250 million of unsecured promissory notes or commercial paper with maturity dates of 12 months or less, but not later than December 31, 2002. GENCO has not sought such authorization. At December 31, 2000 SCE&G had $250 million of unused authorized lines of credit which consist of a credit agreement for a maximum of $250 million to support the issuance of commercial paper SCE&G's commercial paper outstanding at December 31, 2000 and 1999 was $117.5 million and $143.1 million, respectively. In addition, Fuel Company has a credit agreement for a maximum of $125 million with the full amount available at December 31, 2000. The credit agreement supports the issuance of short-term commercial paper for the financing of nuclear and fossil fuels and sulfur dioxide emission allowances. Fuel Company commercial paper outstanding at December 31, 2000 was $70.2 million. This commercial paper and amounts outstanding under the revolving credit agreement, if any, are guaranteed by SCE&G. At December 31, 2000 PSNC had $125 million authorized lines of credit which consist of a credit agreement for a maximum of $125 million to support the issuance of commercial paper. Unused lines of credit at December 31, 2000 totaled $125 million. PSNC's commercial paper outstanding on December 31, 2000 was $125 million. 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, 2000 the Preferred Stock Ratio was 2.09. As a result of SCANA's acquisition of PSNC on February 10, 2000, PSNC shareholders were paid $212 million in cash and 17.4 million shares of SCANA common stock valued at approximately $488 million. In connection with this transaction, certain SCANA shareholders were paid $488 million in cash for 16.3 million shares of SCANA common stock. During 2000, shares for the Stock Purchase Savings Plan and the Investor Plus Plan were purchased on the open market. On September 21, 1999 SCE&G announced a $256 million gas turbine generator project in Aiken County, South Carolina. Two combined-cycle turbines will burn natural gas to produce 300 megawatts of new electric generation and use exhaust heat to replace coal-fired steam that powers two existing 75 megawatt turbines at the Urquhart Generating Station. The turbine project is scheduled to be completed by June 2002. On October 15, 1999 FERC notified SCE&G of its agreement with SCE&G's plan to reinforce Lake Murray Dam in order to maintain the lake in case of an extreme earthquake. SCE&G and FERC have been discussing possible reinforcement alternatives for the dam over the past several years as part of SCE&G's ongoing hydroelectric operating license with FERC. Until discussions are concluded it is not possible to finalize the cost of the project; however, it is possible that the costs could range up to $250 million. Although any costs incurred by SCE&G are expected to be recoverable through electric rates, SCE&G also is exploring alternative sources of funding. The project is expected to be completed in 2004. On October 7, 2000 Summer Station was removed from service for a planned maintenance and refueling outage scheduled to last 38 1/2 days. During initial inspection activities, plant personnel discovered a small leak coming from a hole in a weld in a primary coolant system pipe. SCE&G performed extensive ultrasonic testing of similar welds in the cooling system, which confirmed that the problem was limited to this single weld. A root cause analysis determined that the cause of the crack was primary water stress corrosion cracking. The repair involved cutting out a twelve-inch long spool of the pipe, which included the entire weld, and installing a new spool piece. Repairs have been completed and the integrity of the new welds have been verified through extensive testing. The plant was returned to service in March 2001. The NRC was closely involved throughout this process and approved SCE&G's actions to repair the crack, as well as the restart schedule. SCE&G will continue to monitor primary coolant system pipes during the next outage, scheduled for Spring of 2002. SCE&G recorded a pretax charge of approximately $6 million in the fourth quarter of 2000 to expense repair costs to date. Additional costs that may be recorded in the first quarter of 2001 are not expected to be material. The cost of replacement power is expected to be recovered through SCE&G's electric fuel adjustment clause. In January 2001 SCE&G's 385 megawatt coal-fired Cope Generating Station was taken out of service due to an electrical ground in the generator. The unit is expected to be returned to service in Spring 2001. The cost of replacement power is expected to be recovered through SCE&G's fuel adjustment clause. SCANA and Westvaco each own a 50 percent interest in Cogen South LLC (Cogen). Cogen was formed to build and operate a cogeneration facility at Westvaco's Kraft Division Paper Mill in North Charleston, South Carolina. The facility began operations in March 1999. On September 10, 1998 the contractor in charge of construction filed suit in Circuit Court seeking approximately $52 million from Cogen, alleging that it incurred construction cost overruns relating to the facility and that the construction contract provides for recovery of these costs. In addition to Cogen, Westvaco, SCE&G and SCANA were also named as defendants in the suit. SCANA and the other defendants believe the suit is without merit and are mounting an appropriate defense. SCANA does not believe that the resolution of this issue will have a material impact on its results of operations, cash flows or financial position. Environmental Matters The Clean Air Act (CAA) required electric utilities to reduce emissions of sulfur dioxide and nitrogen oxide substantially by the year 2000. These requirements were phased in over two periods. The first phase had a compliance date of January 1, 1995 and the second, January 1, 2000. The Company's facilities did not require modifications to meet the requirements of Phase I. The Company is meeting the Phase II requirements through the burning of natural gas and/or lower sulfur coal in its generating units and the purchase and use of sulfur dioxide emission allowances. Low nitrogen oxide burners have been installed to reduce nitrogen oxide emissions to the levels required by Phase II. The EPA has indicated that it will propose regulations for stricter limits on mercury and other toxic pollutants generated by coal-fired plants by December 2003 and will begin developing these regulations shortly. SCE&G and GENCO filed compliance plans with DHEC related to Phase II sulfur dioxide requirements in 1995 and Phase II oxides of nitrogen (NOx) requirements in 2000, 1999, 1998 and 1997. The Company currently estimates that air emissions control equipment will require capital expenditures of $141 million over the 2001-2005 period to retrofit existing facilities, with increased operation and maintenance costs of approximately $3 million per year. To meet compliance requirements for the years 2006 through 2010, the Company anticipates additional capital expenditures of approximately $5 million. In October 1998 the EPA issued a final rule requiring 22 states, including South Carolina, to modify their state implementation plans (SIP) to address the issue of NOx pollution. On May 25, 1999 a federal appeals court delayed indefinitely the implementation of the rule. On March 3, 2000 the court affirmed the EPA's NOx rule for the affected states. South Carolina was subsequently ordered to amend its SIP to achieve significant NOx reductions. South Carolina failed to submit a revised SIP as required under the CAA, and the EPA has issued official notice to South Carolina (and a number of other states) to comply. While not final, South Carolina has proposed NOx reductions that would require the Company to install pollution control equipment. Because DHEC had not amended its SIP as of December 31, 2000 to set out or allocate any NOx reductions, it is not possible to estimate what, if any, capital expenditures will be required to comply with any potential mandated reductions. The EPA has undertaken an aggressive enforcement initiative against the industry and the Department of Justice (DOJ) has brought suit against a number of utilities in federal court alleging violations of the CAA. Prior to the suits, those utilities had received requests for information under Section 114 of the CAA, and were issued Notices of Violation prior to the suits. The basis for these suits is the claim by the EPA that maintenance activities undertaken by the utilities over the past 20 or more years constitute "major modifications" which would have required the installation of costly Best Available Control Technology (BACT). The Company and SCE&G have received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. Similar requests have been sent to a number of other utilities nationwide. The regulations under the CAA provide certain exemptions to the definition of "major modifications," particularly an exemption for routine repair, replacement or maintenance. The Company has analyzed each of the activities covered by the EPA's requests and believes each activity represents prudent practice regularly performed throughout the utility industry as necessary to maintain the operational efficiency and safety of equipment. As such, the Company believes that each of these activities is covered by the exemption for routine repair, replacement and maintenance and that the EPA is changing, or attempting to change through enforcement actions, the intent and meaning of its regulations. The Company also believes that, even if some of the activities in question were found not to qualify for the routine exemption, there were no increases either in annual emissions or in the maximum hourly emissions achievable at any of the units caused by any of the activities. The regulations provide an exemption for increased hours of operation or production rate and for increases in emissions resulting from demand growth. It is possible that the EPA will eventually commence enforcement actions against SCE&G relative to those plants. The EPA has the authority to seek penalties for the alleged violations in question at the rate of up to $27,500 per day for each violation. The EPA also would seek installation of BACT (or equivalent) at the three plants as well. The Company believes that the EPA's and DOJ's claims are without merit, and that any enforcement action, up to and including a lawsuit resulting from this issue, will not have a material adverse effect on the Company's financial position or results of operations. The Federal Clean Water Act, as amended, provides for the imposition of effluent limitations that require various levels of treatment for each waste water 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 program in monitoring and controlling thermal discharges and strategies for toxicity reduction in wastewater streams. The Company has been developing compliance plans for these initiatives. Amendments to the Clean Water Act proposed in Congress include several provisions which, if passed, could prove costly to SCE&G and GENCO. These include, but are not limited to, limitations to mixing zones and the implementation of technology-based standards. In December 2000 SCE&G entered into a Consent Order with DHEC related to a malfunction of the waste water treatment facility at Hagood Station. The order requires SCE&G to correct the violation. The Company maintains an environmental assessment program to identify and assess current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate primarily to regulated operations. Such amounts are deferred and amortized with recovery provided through rates. SCE&G has also recovered portions of its environmental liabilities through settlements with various insurance carriers, including all amounts previously deferred for its electric operations. SCE&G expects to recover all deferred amounts related to its gas operations by December 2005. Deferred amounts, net of amounts recovered through rates and insurance settlements, totaled $20.2 million and $23.7 million at December 31, 2000 and 1999, respectively. The deferral includes the estimated costs associated with the following matters. o 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 encompasses approximately 30 acres and includes properties which were locations for industrial operations, including a wood preserving (creosote) plant, one of SCE&G's decommissioned MGPs, properties owned by the National Park Service and the City of Charleston and private properties. The site has not been placed on the National Priorities List, but may be added in the future. The PRPs negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study and a corresponding Scope of Work. Field work began in November 1993, and the EPA approved a Remedial Investigation Report in February 1997 and a Feasibility Study Report in June 1998. In July 1998 the EPA approved SCE&G's Removal Action Work Plan for soil excavation. SCE&G completed Phase One of the Removal Action Work Plan in 1998 at a cost of approximately $1.5 million. Phase Two, which cost approximately $3.5 million, included excavation and installation of several permanent barriers to mitigate coal tar seepage. On September 30, 1998 a Record of Decision was issued which sets forth the EPA's view of the extent of each PRP's responsibility for site contamination and the level to which the site must be remediated. SCE&G estimates that the Record of Decision will result in costs of approximately $13.3 million, of which approximately $2 million remains. On January 13, 1999 the EPA issued a Unilateral Administrative Order for Remedial Design and Remedial Action directing SCE&G to design and carry out a plan of remediation for the Calhoun Park site. SCE&G submitted a Comprehensive Remedial Design Work Plan (RDWP) on December 17, 1999 and proceeded with implementation pending agency approval. The RDWP was approved by the EPA in July 2000, and its implementation continues. In October 1996 the City of Charleston and SCE&G settled all environmental claims the City may have had against SCE&G involving the Calhoun Park area for a payment of $26 million over four years (1996-1999) by SCE&G to the City. SCE&G is recovering the amount of the settlement, which does not encompass site assessment and cleanup costs, through rates in the same manner as other amounts accrued for site assessments and cleanup as discussed above. As part of the environmental settlement, SCE&G constructed an 1,100 space parking garage on the Calhoun Park site (construction was completed in April 2000) and transferred the facility to the City in exchange for a $16.5 million, 18-year municipal bond collaterized by revenues from, and a mortgage on, the parking garage. o SCE&G owns three other decommissioned MGP sites which contain residues of by-product chemicals. For the site located in Sumter, South Carolina, effective September 15, 1998, SCE&G entered into a Remedial Action Plan Contract with DHEC pursuant to which it agreed to undertake a full site investigation and remediation under the oversight of DHEC. Site investigation and characterization are proceeding according to schedule. Upon selection and successful implementation of a site remedy, DHEC will give SCE&G a Certificate of Completion, and a covenant not to sue. For the site located in Florence, South Carolina, SCE&G entered into a similar Remedial Action Plan Contract with DHEC effective September 5, 2000. SCE&G is continuing to investigate the remaining site in Columbia, and is monitoring the nature and extent of residual contamination. In addition, PSNC owns, or has owned, all or portions of seven sites in North Carolina on which MGPs were formerly operated. Intrusive investigation (including drilling, sampling and analysis) has begun at only one site, and the remaining sites have been evaluated using historical records and observations of current site conditions . These evaluations have revealed that MGP residuals are present or suspected at several of the sites. The North Carolina Department of Environment and Natural Resources has recommended that no further action be taken with respect to one site. An environmental due diligence review of PSNC conducted in February 1999 estimated that the cost to remediate the remaining sites would range between $11.3 million to $21.9 million. During the second quarter of 2000, the review was finalized and the estimated liability was recorded. PSNC is unable to determine the rate at which costs may be incurred over this time period. The estimated cost range has not been discounted to present value. PSNC's associated actual costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. An order of the NCUC dated May 11, 1993 authorized deferral accounting for all costs associated with the investigation and remediation of MGP sites. At December 31, 2000 PSNC has recorded a liability and associated regulatory asset of $10.2 million, which reflects the minimum amount of the range, net of shared cost recovery from other PRPs. Amounts incurred to date are not material. Management intends to request recovery of additional MGP cleanup costs not recovered from other PRPs in future rate case filings, and believes that all costs incurred will be recoverable in gas rates. Regulatory Matters South Carolina Electric & Gas Company On July 20, 2000 the PSC issued an order approving SCE&G's request for an out-of-period adjustment to increase the cost of gas component of its rates for natural gas service from 54.334 cents per therm to 68.835 cents per therm, effective with the first billing cycle in August 2000. As part of its regularly scheduled annual review of gas costs, the PSC issued an order on November 9, 2000 which further increased the cost of gas component to 78.151 cents per therm, effective with the first billing cycle in November 2000. On December 21, 2000 the PSC issued an order approving SCE&G's request for another out-of-period adjustment to increase the cost of gas component to 99.340 cents per therm, effective with the first billing cycle in January 2001. In March 2001 the PSC approved SCE&G's request to decrease the cost of gas component to 79.340 cents per therm, effective with the first billing cycle in March 2001. On July 5, 2000 the PSC approved SCE&G's request to implement lower depreciation rates for its gas operations. The new rates were effective retroactively to January 1, 2000 and will result in a reduction in annual depreciation expense of approximately $2.9 million. On September 14, 1999 the PSC approved an accelerated capital recovery plan for SCE&G's Cope Generating Station. The plan was implemented beginning January 1, 2000 for a three-year period. The PSC approved an accelerated capital recovery methodology wherein SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates. The amount of the accelerated depreciation will be determined by SCE&G based on the level of revenues and operating expenses, not to exceed $36 million annually without the approval of the PSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year. As of December 31, 2000 no accelerated depreciation has been recorded. The accelerated capital recovery plan will be accomplished through existing customer rates. On December 11, 1998 the PSC issued an order requiring SCE&G to reduce retail electric rates on a prospective basis. The PSC acted in response to SCE&G reporting that it earned a 13.04 percent return on common equity for its retail electric operations for the 12 months ended September 30, 1998. This return on common equity exceeded SCE&G's authorized return of 12.0 percent by 1.04 percent, or $22.7 million, primarily as a result of record heat experienced during the summer. The order required prospective rate reductions on a per kilowatt-hour basis, based on actual retail sales for the 12 months ended September 30, 1998. On January 12, 1999 the PSC denied SCE&G's motion for reconsideration, ruled that no further rate action was required, and reaffirmed SCE&G's authorized return on equity of 12.0 percent. The rate reductions were placed into effect with the first billing cycle of January 1999. On January 9, 1996 the PSC issued an order granting SCE&G an increase in retail electric rates which were fully implemented by January 1997. The PSC authorized a return on common equity of 12.0 percent. The PSC also approved establishment of a Storm Damage Reserve Account capped at $50 million to be collected through rates over a ten-year period. Additionally, the PSC approved accelerated recovery of a significant portion of SCE&G's electric regulatory assets (excluding deferred income tax assets) and the remaining transition obligation for postretirement benefits other than pensions, changing the amortization periods to allow recovery by the end of the year 2000. SCE&G's request to shift, for rate-making purposes, approximately $257 million of depreciation reserves from transmission and distribution assets to nuclear production assets was also approved. The Consumer Advocate and two other intervenors appealed certain issues in the order initially to the Circuit Court, which affirmed the PSC's decisions, and subsequently, to the Supreme Court. In March 1998, SCE&G, the PSC, the Consumer Advocate and one of the other intervenors reached an agreement that provided for the reversal of the shift in depreciation reserves and the dismissal of the appeal of all other issues. The PSC also authorized SCE&G to adjust depreciation rates that had been approved in the 1996 rate order for its electric transmission, distribution and nuclear production properties to eliminate the effect of the depreciation reserve shift and to retroactively apply such depreciation rates to February 1996. As a result, a one-time reduction in depreciation expense of $9.8 million was recorded in March 1998. The agreement does not affect retail electric rates. The FERC had previously rejected the transfer of depreciation reserves for rates subject to its jurisdiction. In September 1998 the Supreme Court affirmed the Circuit Court's rulings on the issues contested by the remaining intervenor. In 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 MGPs. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for SCE&G's gas operations that had previously been deferred. In November 2000, as a result of the annual review, the PSC approved SCE&G's request to maintain the billing surcharge at $.011 per therm to provide for the recovery of the remaining balance of $20.1 million. In September 1992 the PSC issued an order granting SCE&G's request for a $.25 increase in transit fares from $.50 to $.75 in Columbia, 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 in October 1992. SCE&G appealed the PSC's order to the Circuit Court, which in May 1995 ordered the case back to the PSC for reconsideration of several issues including the low income rider program, routing changes, and the $.75 fare. The Supreme Court declined to review an appeal of the Circuit Court decision and dismissed the case. The PSC and other intervenors filed another Petition for Reconsideration, which the Supreme Court denied. The PSC and other intervenors filed another appeal to the Circuit Court which the Circuit Court denied in an order dated May 9, 1996. In this order, the Circuit Court upheld its previous orders and remanded them to the PSC. During August 1996 the PSC heard oral arguments on the orders on remand from the Circuit Court. On September 30, 1996 the PSC issued an order affirming its previous orders and denied SCE&G's request for reconsideration. In response to an appeal of the PSC's order by SCE&G, the Circuit Court issued an order on May 25, 2000, which remanded the matter to the PSC for review of SCE&G's original application and request to terminate the low income rider fare. On September 27, 2000 the PSC issued an order granting the relief requested by SCE&G. On September 29, 2000 the Consumer Advocate filed a motion with the PSC for a stay of this order to which SCE&G filed a response. On October 3, 2000 the PSC accepted the Consumer Advocate's motion and issued a stay of its order. The Consumer Advocate and other intervenors have petitioned the Circuit Court for judicial review of the PSC's order granting relief. Action by the Circuit Court is pending. Public Service Company of North Carolina, Incorporated A state expansion fund, established by the North Carolina General Assembly in 1991 and funded by refunds from PSNC's interstate pipeline transporters, provides financing for expansion into areas that otherwise would not be economically feasible to serve. On December 30, 1999 PSNC filed an application with the NCUC to extend natural gas service to Madison, Jackson and Swain Counties, North Carolina. Pursuant to state statutes, the NCUC required PSNC to forfeit its exclusive franchises to serve six counties in western North Carolina effective January 31, 2000 because these counties were not receiving any natural gas service. Madison, Jackson and Swain Counties were included in the forfeiture order. On June 29, 2000 the NCUC approved PSNC's requests for reinstatement of its exclusive franchises for Madison, Jackson and Swain Counties and disbursement of up to $28.4 million from PSNC's expansion fund for this project. PSNC estimates that the cost of this project will be approximately $31.4 million. On December 7, 1999 the NCUC issued an order approving the acquisition of PSNC by the Company. As specified in the NCUC order, PSNC reduced its rates by approximately $1 million in August 2000, will reduce rates another $1 million in August 2001 and has agreed to a five-year moratorium on general rate cases. General rate relief can be obtained during this period to recover costs associated with materially adverse governmental actions and force majeure events. On February 22, 1999 the NCUC approved PSNC's application to use expansion funds to extend natural gas service into Alexander County and authorized disbursements from the fund of approximately $4.3 million based upon budgeted construction cost of approximately $6.2 million. Most of Alexander County lies within PSNC's certificated service territory and did not previously have natural gas service. The project was completed and customers began receiving natural gas service in March 2000. On October 30, 1998 the NCUC issued an order in PSNC's general rate case filed in April 1998. The order, effective November 1, 1998, granted PSNC additional revenue of $12.4 million and allowed a 9.82 percent overall rate of return on PSNC's net utility investment. It also approved the continuation of the Weather Normalization Adjustment and Rider D Mechanisms and full margin transportation rates. PSNC's Rider D rate mechanism authorizes the recovery of all prudently incurred gas costs from customers on a monthly basis. Any difference in amounts paid and collected for these costs is deferred for subsequent refund to or collection from customers. On February 4, 2000, in response to an appeal by CUCA, the Supreme Court of North Carolina affirmed the NCUC order. On November 6, 1997 the NCUC issued an order permitting PSNC, on a trial basis, to establish its commodity cost of gas for large commercial and industrial customers on the basis of market prices for natural gas. PSNC's request for permanent approval of this mechanism was approved by the NCUC via an order issued April 6, 2000. The Company's regulated business operations were impacted by the NEPA and FERC Orders No. 636, 888 and 2000. NEPA was designed to create a more competitive wholesale power supply market by creating "exempt wholesale generators" and by potentially requiring utilities owning transmission facilities to provide transmission access to wholesalers. Order No. 636 was intended to deregulate the markets for interstate sales of natural gas by requiring that pipelines provide transportation services that are equal in quality for all gas suppliers whether the customer purchases gas from the pipeline or another supplier. Orders No. 888 and 2000 require utilities under FERC jurisdiction that own, control or operate transmission lines to file nondiscriminatory open access tariffs that offer to others the same transmission service they provide to themselves and to submit plans for the possible formulation of an RTO. In the opinion of the Company, it continues to be able to meet successfully the challenges of these altered business climates and does not anticipate any material adverse impact on the results of operations, cash flows, financial position or business prospects. Other At December 31, 2000 SCANA Communications Holdings, Inc. (SCH), a wholly owned, indirect subsidiary of SCANA, held the following investments in ITC Holding Company, Inc. (ITC) and its affiliates: o Powertel, Inc. (Powertel) is a publicly traded company that owns and operates personal communications services (PCS) systems in several major Southeastern markets. SCH owns approximately 4.9 million common shares of Powertel at a cost of approximately $77.7 million. Powertel common stock closed at $61.9375 per share on December 31, 2000, resulting in a pre-tax unrealized holding gain of $228.8 million (a decline of $189.0 million from December 31, 1999). Accumulated other comprehensive income includes the after-tax amount of all unrealized holding gains and losses on common shares. In addition, SCH owns the following series of non-voting convertible preferred shares, at the approximate cost noted: 100,000 shares series B ($75.1 million); 50,000 shares series D ($22.5 million); and 50,000 shares 6.5 percent series E ($75.0 million). Cumulative dividends on preferred series E shares are generally paid in common shares of Powertel and are accrued quarterly. Preferred series B shares become convertible in March 2002 at a conversion price of $16.50 per common share or approximately 4.6 million common shares. Preferred series D shares become convertible in March 2002 at a conversion price of $12.75 per common share or approximately 1.7 million common shares. Preferred series E shares become convertible in June 2003 at a conversion price of $22.01 per common share or approximately 3.4 million common shares. The market value of the convertible preferred shares of Powertel is not readily determinable. However, as converted, the market value of the underlying common shares for the preferred shares was approximately $606.9 million at December 31, 2000, reflecting an unrecorded pre-tax holding gain of $434.3 million (a decline of $368.4 million from December 31, 1999). OnAugust 28, 2000 SCH announced that under terms of separate definitive agreements, Powertel has agreed to be acquired by either Deutsche Telekom AG or VoiceStream Wireless Corporation (VoiceStream). If Deutsche Telekom's previously announced acquisition of VoiceStream is successfully completed, then Deutsche Telekom would also acquire Powertel. If the Deutsche Telekom - VoiceStream transaction is not completed, then VoiceStream would acquire Powertel. In connection with these transactions, SCH entered into stockholder agreements with each of Deutsche Telekom and VoiceStream pursuant to which SCH agreed to vote its Powertel shares in support of either of these transactions. In addition, SCH agreed to certain restrictions on disposition of its Powertel shares and the shares it would receive in either of these transactions. On March 13, 2001 Powertel shareholders approved the acquisition agreements. o ITC^DeltaCom, Inc. (ITCD) is a fiber optic telecommunications provider. SCH owns approximately 5.1 million common shares of ITCD at a cost of approximately $43.0 million. ITCD common stock closed at $5.39 per share on December 31, 2000, resulting in a pre-tax unrealized holding loss of $15.4 million (a decline of $113.7 million from December 31, 1999). Accumulated other comprehensive income includes the after-tax amount of all unrealized holding gains and losses on common shares. In addition, SCH owns 1,480,771 shares of series A preferred stock of ITCD at a cost of approximately $11.2 million. Series A preferred shares become convertible in March 2002 into 2,961,542 shares of ITCD common stock. The market value of series A preferred stock of ITCD is not readily determinable. However, as converted, the market value of the underlying common stock for the series A preferred stock was approximately $16.0 million at December 31, 2000, reflecting an unrecorded pre-tax holding gain of $4.8 million (a decline of $65.8 million from December 31, 1999). o Knology, Inc. (Knology) is a broad-band service provider of cable television, telephone and internet services. SCH owns $71,050,000 face amount of 11.875 percent Senior Discount Notes due 2007 of Knology Broadband, Inc., a wholly-owned subsidiary of Knology. The Senior Discount Notes have a book basis at December 31, 2000 of approximately $57.9 million. In addition, SCH owns approximately 7.2 million shares of Knology Series A Convertible Preferred Stock with a cost basis of approximately $5.0 million and warrants to purchase approximately 0.2 million shares of Series A Convertible Preferred Stock. On January 12, 2001 SCH invested $25.0 million for approximately 8.3 million shares of Series C Convertible Preferred Stock of Knology. The market value of these investments is not readily determinable. o ITC holds ownership interests in several Southeastern communications companies, including those discussed above. SCH owns approximately 3.1 million common shares, 645,153 series A convertible preferred shares, and 133,664 series B convertible preferred shares of ITC. These investments cost approximately $5.8 million, $7.2 million, and $4.0 million, respectively. The market values of these investments are not readily determinable. In June 1998 the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) 133, "Accounting for Derivative Instruments and Hedging Activities." In June 2000, the FASB issued SFAS 138, which amends certain provisions of SFAS 133 to expand the normal purchase and sale exemption for supply contracts and to redefine interest rate risk to reduce sources of ineffectiveness, among other things. The Company utilizes various derivatives in its risk management activities, including swaps and commodities futures. The Company adopted SFAS 133, as amended, on January 1, 2001. As a result of adopting SFAS 133, the Company recorded a credit of approximately $23.0 million, net of tax, as the effect of a change in accounting principle (transition adjustment) to other comprehensive income on January 1, 2001. This amount represents the reclassification of unrealized gains that were deferred and reported as liabilities at December 31, 2000. In the future, all gains/losses related to qualifying cash flow hedges deferred in other comprehensive income will be reclassified to earnings at the time the hedged transaction affects earnings. In December 1999 Staff Accounting Bulletin No. 101, "Revenue Recognition in Financial Statements" was issued by the SEC, and provides the SEC staff's views in applying generally accepted accounting principles to selected revenue recognition issues. The Company's adoption of this bulletin in the fourth quarter of 2000 had no impact on its results of operations, cash flows or financial position. ServiceCare, Inc. has announced the sale of its home security business, expected to be completed in March 2001. SCANA Communications, Inc. has signed a letter of intent to sell its 800 Mhz radio service network, expected to be completed in April 2001. RESULTS OF OPERATIONS Earnings and Dividends Earnings per share of common stock and the rate of return earned on common equity for 2000, 1999 and 1998 were as follows: 2000 1999 1998 -------------------------------------------------------------------------- -------------------------------------------------------------------------- Earnings derived from: Continuing operations $2.12 $1.39 $2.07 Non-recurring gains - .34 .05 Cumulative effect of accounting change, net of taxes .28 - - -------------------------------------------------------------------------- Earnings per weighted average share $2.40 $1.73 $2.12 ========================================================================== Return earned on common equity 12.3% 8.5% 12.8% -------------------------------------------------------------------------- o 2000 vs 1999 Earnings derived from continuing operations increased $0.73, primarily as a result of improved results from retail gas marketing ($.04 net earnings for 2000 compared to $.45 loss in 1999) and the acquisition of PSNC ($.21). In addition, electric margin improved $.36 (see discussion at Electric Operations), regulated gas margin (excluding PSNC) improved $.07 and pension income increased $.05. These improvements were partially offset by increased interest expense of $.36, a charge for repairs at Summer Station ($.04) and other increases in operations and maintenance ($.05). o 1999 vs 1998 Earnings derived from continuing operations decreased $.68, primarily as a result of losses from the Company's entry into the Georgia retail gas market ($.37 greater loss in 1999). In addition, electric margin decreased $.12 (see discussion at Electric Operations), gas margin decreased $.04, and expenses were higher for other operations and maintenance ($.04), depreciation and amortization ($.09) and interest expense ($.11). These decreases were partially offset by improved results from energy marketing activities ($.03), the impact of fewer common shares outstanding ($.03), and other ($.03). Pension income recorded by the Company reduced operations expense by $22.7 million, $17.3 million and $16.9 million for the years ended December 31, 2000, 1999 and 1998, respectively. In addition pension income increased other income by $12.8 million, $10.5 million and $9.0 million for the years ended December 31, 2000, 1999 and 1998, respectively. The reductions to operations expense for 1999 and 1998 were substantially offset by accelerated amortization of a significant portion of the transition obligation for postretirement benefits other than pensions and certain regulatory assets as approved by the PSC. Effective July 1, 2000 the Company's pension plan was amended to provide a cash balance formula. The effect of this plan amendment was to reduce net periodic benefit income for the year ended December 31, 2000 by approximately $3.7 million. Non-recurring gains resulted from the sale of retail propane assets ($.29) and telecommunications towers ($.05) in 1999 and a retroactive change in electric depreciation rates ($.05) in 1998. In 2000 the cumulative effect of an accounting change resulted from the recording of unbilled revenues by SCANA's retail utility subsidiaries (see Note 2 of Notes To Consolidated Financial Statements). Return on common equity increased in 2000 primarily due to increased earnings and decreased common equity due to a $197 million unrealized loss on the Company's investment in telecommunications securities during the year. Increased earnings related to the cumulative effect of accounting change increased the return on common equity by 1.4 percent in 2000. In addition, the $197 million unrealized loss on the Company's investments in telecommunications securities increased the return on common equity by 1.1 percent in 2000. Return on common equity decreased in 1999 due to decreased earnings and a $311 million unrealized gain on the Company's investments in telecommunications securities. The increase in common equity, without a proportional increase in net income, decreased the return earned on common equity by 1.6 percent in 1999. 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 2.3 percent of income before income taxes in 2000, 2.4 percent in 1999 and 4.4 percent in 1998. On February 22, 2000 the Board of Directors set the Company's indicated annual dividend rate on common stock at $1.15 per share. Electric Operations Electric Operations is comprised of the electric portion of SCE&G, GENCO and Fuel Company. Electric operations sales margins, including transactions with affiliates and excluding the cumulative effect of accounting change, for 2000, 1999 and 1998 were as follows: Millions of dollars 2000 1999 1998 ---------------------------------------------- ------------- --------------- Operating revenues $1,343.8 $1,226.0 $1,219.8 Less: Fuel used in generation (294.9) (284.6) (262.3) Purchased power (82.5) (35.9) (31.5) ------------------------------------------- ---------------- --------------- Margin $966.4 $905.5 $926.0 =========================================== ================ =============== o 2000 vs 1999 Sales margin increased primarily due to more favorable weather and customer growth, which were partially offset by higher purchased power costs. o 1999 vs 1998 Sales margin decreased primarily due to the impact of a rate reduction at SCE&G and milder weather, which were partially offset by customer growth. Increases (decreases) from the prior year in megawatt-hour (MWH) sales volume by classes, excluding volumes attributable to the cumulative effect of accounting change, were as follows: Classification 2000 % Change 1999 % Change ------------------------------------------- ----------- ----------------------- Residential 396,179 6.3% (55,207) (0.9%) Commercial 354,350 6.0% 51,212 0.9% Industrial 524,969 8.5% 316,087 5.4% Sales for Resale (excluding interchange) 33,505 2.8% 63,306 5.6% Other 34,676 6.7% (17,652) (3.3%) ---------- ------- ------------------------------- Total territorial 1,343,679 6.7% 357,746 1.8% Negotiated Market Sales Tariff 264,257 15.7% 183,442 12.3% -- ------- ------- ------------------------------- Total 1,607,936 7.4% 541,188 2.6% =========================================== =========== ======================= o 2000 vs 1999 Sales volume increased primarily due to more favorable weather and customer growth. o 1999 vs 1998 Sales volume decreased for residential primarily due to milder weather, which was partially offset by customer growth. Volumes for the remaining classes increased primarily due to customer growth. Gas Distribution Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC. Gas distribution sales margins, including transactions with affiliates and excluding the cumulative effect of accounting change, for 2000, 1999 and 1998 were as follows: Millions of dollars 2000 1999 1998 ----------------------------------------------- ------------- ------------- Operating revenues $745.9 $239.0 $230.4 Less: Gas purchased for resale (486.3) (152.6) (142.4) ----------------------------------------------- ------------- ------------- Margin $259.6 $86.4 $88.0 =============================================== ============= ============= SCANA acquired PSNC effective January 1, 2000. Therefore the Company's prior year sales do not include PSNC. o 2000 vs 1999 Sales margin increased primarily due to the acquisition of PSNC, which contributed $161.5 million, and improved margin at SCE&G due primarily to more favorable weather. o 1999 vs 1998 Sales margin decreased primarily as a result of higher gas costs. Increases (decreases) from the prior year in dekatherm (DT) sales volume by classes, including transportation gas and excluding volumes attributable to the cumulative effect of accounting change were as follows: Classification 2000 % Change 1999 % Change ----------------------------------- -------------- -------------- ------------- Residential 23,541,979 199.1% (94,027) (0.8%) Commercial 13,227,028 113.1% 404,654 3.6% Industrial 4,478,371 24.9% 644,485 3.7% Transportation gas 29,482,223 1,492.8% (28,732) (1.4%) Sales for resale 407 - - - ------------- ------------- --------------------- Total 70,730,008 162.8% 926,380 2.2% =================================== ============== ============== ============= o 2000 vs 1999 Sales volume increased primarily as a result of the acquisition of PSNC, which accounted for 65.2 million DTs. SCE&G's sales volume increased approximately 2.0 million DTs due to colder weather and customer growth, which were partially offset by curtailments and use of alternate fuels by industrial customers. o 1999 vs 1998 Sales volume increased primarily as a result of customer growth. Residential volume decreased primarily due to milder weather. Gas Transmission Gas Transmission is comprised of Pipeline Corporation. Gas transmission sales margins for 2000, 1999 and 1998, including transactions with affiliates, were as follows: Millions of dollars 2000 1999 1998 -------------------------------------------- -------------- ------------- Operating revenues $489.0 $342.4 $329.8 Less: Gas purchased for resale (434.7) (295.1) (276.7) -------------------------------------------- -------------- ------------- Margin $54.3 $47.3 $53.1 ============================================ ============== ============= o 2000 vs 1999 Sales margin increased primarily as a result of increased contract and sales volumes from the sale for resale classification and margin earned from the competitive industrial customers. o 1999 vs 1998 Sales margin decreased primarily as a result of increased competition with oil prices and a decrease in the value of released capacity on the intrastate pipeline system. Increases (decreases) from the prior year in dekatherms (DT) sales volume by classes including transportation were as follows: Classification 2000 % Change 1999 % Change ----------------------------------- --------------------------------------- Commercial 22,132 24.2% 200 0.2% Industrial (5,212,904) (11.7%) (916,235) (2.0%) Transportation 10,296 0.5% (179,029) (7.4%) Sales for resale 3,542,185 6.0% 2,122,252 3.8% =================================== =========== Total (1,638,291) (1.6%) 1,027,188 1.0% =================================== ======================================= o 2000 vs 1999 Sales for resale volumes increased as a result of colder temperatures. The sales volume for industrial customers decreased due to decreased sales to electric generation facilities and decreased sales to other customers with alternate fuel sources. o 1999 vs 1998 Sales volumes for sales for resale customers increased for 1999 as a result of customer growth and customer expansion on our sale for resale customers' systems. Transportation and industrial volumes decreased due to increased competition with oil prices. Retail Gas Marketing Retail Gas Marketing is comprised of SCANA Energy, a division of SCANA Energy Marketing, Inc., which operates in Georgia's deregulated natural gas market. Retail gas marketing revenues and net income for 2000, 1999 and 1998 were as follows: Millions of dollars 2000 1999 1998 -------------------------------------- --------------- ---------------- Operating revenues $547.3 $206.6 $3.5 Net income (loss) 4.4 (44.8) (7.9) -------------------------------------- --------------- ---------------- o 2000 vs 1999Operating revenues increased as a result of customer growth, favorable weather and a successful gas supply and pricing strategy. Net income increased as a result of the increase in revenue and significant reductions in customer acquisition and advertising expenditures. o 1999 vs 1998 Operating revenues increased as a result of a full year of operations being reflected in 1999's results. Net loss increased as a result of large expenditures for marketing and advertising reflected in 1999's results. Delivered volumes for 2000, 1999 and 1998 totaled approximately 73.8 million, 40.9 million and 0.5 million DT, respectively, which includes interruptible volumes of approximately 30.6 million, 18.9 million and 0.0 million DT for the same periods, respectively. The increases in volumes resulted from customer growth. Energy Marketing Energy Marketing is comprised of the Company's non-regulated marketing operations, excluding SCANA Energy. Energy marketing operating revenues and net losses for 2000, 1999 and 1998 were as follows: Millions of dollars 2000 1999 1998 ------------------------------------------ --------------- ---------------- Operating revenues $543.3 $223.3 $564.6 Net loss (4.2) (3.9) (6.6) ------------------------------------------ --------------- ---------------- o 2000 vs 1999Operating revenues increased primarily due to increased prices for natural gas. Net loss increased primarily due to increased bad debts. o 1999 vs 1998Operating revenues and net loss decreased primarily due to the closing of the Houston office. Delivered volumes for 2000, 1999 and 1998 totaled approximately 83.9 million, 103.7 million and 218.5 million DT, respectively. The decreases in volumes resulted from the closing of the Houston office. Other Operating Expenses Increases in other operating expenses were as follows: (Millions of dollars) 2000 % Change 1999 % Change ----------------------------------------- -------------------------------------- Other operation and maintenance $66.1 16.1% $60.4 17.2% Depreciation and amortization 47.4 28.1% 24.3 16.8% Other taxes 10.6 10.3% 1.9 1.8% ========================================= ============= Total $124.1 18.2% $86.6 14.5% ========================================= ====================================== o 2000 vs 1999 Other operating expenses and taxes increased primarily as a result of the acquisition of PSNC. This acquisition accounted for the following increases: other operation and maintenance ($67.5 million), depreciation and amortization ($41.9 million, of which $13.4 million is attributable to the amortization of the acquisition adjustment), and other taxes ($6.4 million). Apart from the PSNC acquisition, other operation and maintenance expense decreased $1.4 million due to pension income (see Earnings and Dividends), which was partially offset by increased maintenance costs for electric generating and distribution facilities. Depreciation and amortization increased $5.5 million primarily due to normal increases in utility plant. Other taxes increased $4.2 million primarily due to increased property taxes. o 1999 vs 1998 Other operation and maintenance increased primarily due to costs associated with a cogeneration facility becoming operational, costs associated with an early retirement program and other operating costs. These costs were partially offset by pension income, which in 1998 had been offset by the accelerated amortization of the electric portion of the Company's transition obligation expense for post-retirement benefits and other regulatory assets. Depreciation and amortization increased primarily due to the impact of the non-recurring adjustment to depreciation expense discussed under earnings and dividends, increased amortization due to completion of a new customer billing system and normal increases in utility plant. Other taxes increased primarily due to increased property taxes. Other Income Other income decreased approximately $46.6 million for the year 2000 compared to 1999, primarily as a result of 1999 including the sale of nonregulated propane assets and telecommunications towers, which was partially offset by other income at PSNC in 2000. Other income increased approximately $71.1 million for the year 1999 compared to 1998, primarily as a result of the sale of assets discussed previously and pension income. Interest Expense Increases in interest expense, excluding the debt component of AFC, were as follows: (Millions of dollars) 2000 1999 ----------------------------------------------- -------------------- Interest on long-term debt, net $73.8 $11.4 Other interest expense 10.6 3.9 ----------------------------------------------- -------------------- Total $84.4 $15.3 =============================================== ==================== o 2000 vs 1999Interest expense increased primarily as a result of financing the acquisition of PSNC and related repurchase of SCANA shares ($46.0 million) and interest incurred on PSNC debt that was assumed as a result of the acquisition ($19.6 million). In addition, interest expense increased as a result of increased borrowings and increased weighted average interest rates on long-term and short-term borrowings. o 1999 vs 1998Interest expense increased as a result of increased long-term debt and increased weighted average interest rates on long-term and short-term borrowings. Income Taxes Income taxes increased approximately $29.7 million for the year 2000 compared to 1999 and decreased approximately $19.8 million for the year 1999 compared to 1998. Changes in income taxes are primarily due to changes in operating income. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK All financial instruments held by the Company described below are held for purposes other than trading. Interest rate risk - The table below provides information about the Company's financial instruments that are sensitive to changes in interest rates. For debt obligations the table presents principal cash flows and related weighted average interest rates by expected maturity dates. December 31, 2000 Expected Maturity Date (Millions of dollars) Liabilities 2001 2002 2003 2004 2005 Thereafter Total Fair Value -------------------------------- --------- ---------- ---------- ---------- ---------- ----------- ---------- -------------- Long-Term Debt: Fixed Rate ($)(1) 40.9 337.3 297.2 186.3 182.0 1,267.4 2,311.1 2,232.2 Average Fixed Interest Rate 7.27% 7.36% 6.38% 7.58% 7.43% 7.35% 7.25% Variable Rate ($) - 550.0 150.0 - - - 700.0 699.7 Average Variable Interest Rate - 7.26% 7.48% - - - 7.31% December 31, 1999 Expected Maturity Date (Millions of dollars) Liabilities 2000 2001 2002 2003 2004 Thereafter Total Fair Value -------------------------------- --------- --------- --------- ---------- ----------- ----------- ----------- -------------- Long-Term Debt: Fixed Rate ($) (1) 152.5 32.5 32.5 289.3 178.8 1,150.5 1,836.1 1,680.7 Average Fixed Interest Rate 6.20% 6.85% 6.85% 6.17% 7.50% 7.33% 7.05% Variable Rate ($) 150.0 - - - - - 150.0 150.0 Average Variable Interest Rate 6.45% - - - - - - (1) At December 31, 1999 there were no debt issuances outstanding under the $300 million credit agreement. At December 31, 2000 the entire $300 million was outstanding. While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur. In addition the Company has invested in a telecommunications company approximately $40 million for 11.875 percent senior discount notes due 2007. The fair value of these notes approximates cost. An increase in market interest rates would result in a decrease in fair value of these notes and a corresponding adjustment, net of tax effect, to other comprehensive income. Commodity price risk - The table below provides information about the Company's financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 mmbtu. December 31, 2000 Expected Maturity in 2001 (Millions of dollars) Weighted Avg Contract Fair Natural Gas Derivatives: Settlement Price Amount Value ---------------------------------------------------- ------------- ------------- Future Contracts: Long $6.5870 $57.2 $81.5 Short $6.2957 $1.4 $2.1 SET Futures Contracts (1): Long $6.5239 $2.8 $4.4 Short - - - December 31, 1999 Expected Maturity in 2000 (Millions of dollars) Weighted Avg Contract Fair Natural Gas Derivatives: Settlement Price Amount Value ----------------------------------------------------- ------------ ------------- Future Contracts: Long $2.3318 $20.0 $19.8 Short $2.3290 $1.2 $1.1 SET Futures Contracts (1): Long $2.7161 $5.0 $5.1 Short $2.7461 $4.7 $4.8 (1) SCANA Energy Trading, LLC (SET) is a 70 percent owned subsidiary of SCANA Energy Marketing, Inc. Amounts shown are at 100 percent. Equity price risk - Certain investments in telecommunications companies' marketable equity securities are carried at their market value of $597.8 million. A ten percent decline in market value would result in a $59.8 million reduction in fair value and a corresponding adjustment, net of tax effect, to the related equity account for unrealized gains/losses, a component of other comprehensive income. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA TABLE OF CONTENTS OF CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL DATA Page Independent Auditors' Report............................................. 43 Consolidated Financial Statements: Consolidated Balance Sheets as of December 31, 2000 and 1999............. 44 Consolidated Statements of Income and Retained Earnings for the Years Ended December 31, 2000, 1999 and 1998................ 46 Consolidated Statements of Cash Flows for the Years Ended December 31, 2000, 1999 and 1998.................................... 47 Consolidated Statements of Capitalization as of December 31, 2000 and 1999.......................................... 48 Consolidated Statements of Changes in Common Equity for the Years Ended December 31, 2000, 1999 and 1998............................... 52 Notes to Consolidated Financial Statements............................... 53 INDEPENDENT AUDITORS' REPORT SCANA Corporation: We have audited the accompanying Consolidated Balance Sheets and Statements of Capitalization of SCANA Corporation (Company) as of December 31, 2000 and 1999 and the related Consolidated Statements of Income and Retained Earnings, Changes in Common Equity and Cash Flows for each of the three years in the period ended December 31, 2000. Our audits also include the financial statement schedule listed in Part IV at Item 14. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, 2000 and 1999 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein. As discussed in Note 2 to the consolidated financial statements, effective January 1, 2000, the Company changed its method of accounting for operating revenues associated with its regulated utility operations. s/Deloitte & Touche LLP DELOITTE & TOUCHE LLP Columbia, South Carolina February 7, 2001 (February 16, 2001 as to Note 15) SCANA Corporation CONSOLIDATED BALANCE SHEETS ----------------------------------------------------------------------------- ------------------- --------------------- December 31, (Millions of dollars) 2000 1999 ----------------------------------------------------------------------------- ------------------- --------------------- Assets Utility Plant (Notes 1 & 6): Electric $4,747 $4,633 Gas 1,435 632 Other 187 191 ----------------------------------------------------------------------------- ------------------- --------------------- Total 6,369 5,456 Less accumulated depreciation and amortization 2,212 1,829 ----------------------------------------------------------------------------- ------------------- --------------------- Total 4,157 3,627 Construction work in progress 261 159 Nuclear fuel, net of accumulated amortization 57 43 Acquisition adjustment-gas, net of accumulated amortization (Note 3) 474 22 ----------------------------------------------------------------------------- ------------------- --------------------- Utility Plant, Net 4,949 3,851 ----------------------------------------------------------------------------- ------------------- --------------------- Nonutility Property, net of accumulated depreciation 79 61 Investments (Note 12) 203 938 ----------------------------------------------------------------------------- ------------------- --------------------- Nonutility Property and Investments, net of accumulated depreciation 282 999 ----------------------------------------------------------------------------- ------------------- --------------------- Current Assets: Cash and temporary cash investments (Notes 1 & 12) 159 116 Receivables (net of provision for uncollectible accounts of $31 million in 2000 and $7 million in 1999) 699 318 Inventories (At average cost) (Note 7): Fuel 107 82 Materials and supplies 56 51 Emission allowances 20 17 Prepayments 16 18 Investments (Note 12) 479 - Deferred income taxes, net (Notes 1 & 11) - 16 ----------------------------------------------------------------------------- ------------------- --------------------- Total Current Assets 1,536 618 ----------------------------------------------------------------------------- ------------------- --------------------- Deferred Debits: Emission allowances 3 14 Environmental 30 24 Nuclear plant decommissioning fund (Note 1) 72 64 Pension asset, net (Note 5) 196 144 Other regulatory assets (Note 1) 213 175 Other 139 122 ----------------------------------------------------------------------------- ------------------- --------------------- Total Deferred Debits 653 543 ----------------------------------------------------------------------------- ------------------- --------------------- Total $7,420 $6,011 ============================================================================= =================== ===================== 169 ----------------------------------------------------------------------- --------------------- --------------------- December 31, (Millions of dollars) 2000 1999 ----------------------------------------------------------------------- --------------------- --------------------- Capitalization and Liabilities Stockholders' Investment: Common Equity (Note 9) $2,032 $2,099 Preferred stock (Not subject to purchase or sinking funds) (Note 10) 106 106 ----------------------------------------------------------------------- --------------------- --------------------- Total Stockholders' Investment 2,138 2,205 Preferred Stock, net (Subject to purchase or sinking funds) 10 11 SCE&G-Obligated Mandatorily Redeemable Preferred Securities of SCE&G's Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount of the 7.55% Junior Subordinated Debentures of SCE&G, due 2027 (Note 10) 50 50 Long-Term Debt, net (Notes 6 & 12) 2,850 1,563 ----------------------------------------------------------------------- --------------------- --------------------- Total Capitalization 5,048 3,829 ----------------------------------------------------------------------- --------------------- --------------------- Current Liabilities: Short-term borrowings (Notes 7, 8 & 12) 398 266 Current portion of long-term debt (Note 6) 41 303 Accounts payable 396 189 Customer deposits 25 16 Taxes accrued 54 86 Interest accrued 42 29 Dividends declared 32 31 Deferred income taxes, net (Notes 1 & 11) 98 - Other 25 13 ----------------------------------------------------------------------- --------------------- --------------------- Total Current Liabilities 1,111 933 ----------------------------------------------------------------------- --------------------- --------------------- Deferred Credits: Deferred income taxes, net (Notes 1 & 11) 721 805 Deferred investment tax credits (Notes 1 & 11) 119 116 Reserve for nuclear plant decommissioning (Note 1) 72 64 Postretirement benefits (Note 5) 113 98 Other regulatory liabilities 75 64 Other (Note 1) 161 102 ----------------------------------------------------------------------- --------------------- --------------------- Total Deferred Credits 1,261 1,249 ----------------------------------------------------------------------- --------------------- --------------------- Commitments and Contingencies (Note 13) - - ----------------------------------------------------------------------- --------------------- --------------------- Total $7,420 $6,011 ======================================================================= ===================== ===================== See Notes to Consolidated Financial Statements. SCANA Corporation CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS -------------------------------------------------------------------------- ---------------- --------------- -------------- -- For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------- ---------------- --------------- -------------- -- (Millions of Dollars, except per share amounts) Operating Revenues (Notes 1, 2 & 4): Electric $1,344 $1,226 $1,220 Gas - Regulated 998 422 411 Gas - Nonregulated 1,091 430 475 -------------------------------------------------------------------------- ---------------- --------------- ---------------- Total Operating Revenues 3,433 2,078 2,106 -------------------------------------------------------------------------- ---------------- --------------- ---------------- Operating Expenses: Fuel used in electric generation 295 285 262 Purchased power 82 36 31 Gas purchased for resale 1,694 721 746 Other operation and maintenance (Note 1) 477 411 351 Depreciation and amortization (Note 1) 217 169 145 Other taxes 114 103 101 -------------------------------------------------------------------------- ---------------- --------------- ---------------- Total Operating Expenses 2,879 1,725 1,636 -------------------------------------------------------------------------- ---------------- --------------- ---------------- Operating Income 554 353 470 -------------------------------------------------------------------------- ---------------- --------------- ---------------- Other Income: Other income, including allowance for equity funds used during construction (Note 1) 41 22 19 Gain on sale of subsidiary assets 3 68 - -------------------------------------------------------------------------- ---------------- --------------- ---------------- Total Other Income 44 90 19 -------------------------------------------------------------------------- ---------------- --------------- ---------------- Income Before Interest Charges, Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change 598 443 489 -------------------------------------------------------------------------- ---------------- --------------- ---------------- Interest Charges: Interest expense on long-term debt, net 206 132 121 Other interest expense, net of allowance for borrowed funds used during construction (Note 1) 19 10 2 -------------------------------------------------------------------------- ---------------- --------------- ---------------- Total Interest Charges, Net 225 142 123 -------------------------------------------------------------------------- ---------------- --------------- ---------------- Income Before Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change 373 301 366 Income Taxes (Note 11) 141 111 131 -------------------------------------------------------------------------- ---------------- --------------- ---------------- Income Before Preferred Stock Dividends and Cumulative Effect of Accounting Change 232 190 235 Preferred Dividend Requirement of SCE&G - Obligated Mandatorily Redeemable Preferred Securities 4 4 4 -------------------------------------------------------------------------- ---------------- --------------- ---------------- Income Before Cash Dividends on Preferred Stock of Subsidiary and Cumulative Effect of Accounting Change 228 186 231 Cash Dividends on Preferred Stock of Subsidiary (At stated rates) 7 7 8 -------------------------------------------------------------------------- ---------------- --------------- ---------------- Income Before Cumulative Effect of Accounting Change 221 179 223 Cumulative Effect of Accounting Change, net of taxes (Note 2) 29 - - -------------------------------------------------------------------------- ---------------- --------------- ---------------- Net Income 250 179 223 Retained Earnings at Beginning of Year 720 678 617 Common Stock Cash Dividends Declared (120) (137) (162) ========================================================================== ================ =============== ================ Retained Earnings at End of Year $850 $720 $678 ========================================================================== ================ =============== ================ Basic and Diluted Earnings Per Share of Common Stock: Before Cumulative Effect of Accounting Change $2.12 $1.73 $2.12 Cumulative Effect of Accounting Change, net of taxes (Note 2) .28 - - ========================================================================== ================ =============== ================ Basic and diluted earnings per share $2.40 $1.73 $2.12 ========================================================================== ================ =============== ================ Weighted average shares outstanding (millions) 104.5 103.6 105.3 ========================================================================== ================ =============== ================ See Notes to Consolidated Financial Statements. SCANA Corporation CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, (Millions of dollars) 2000 1999 1998 ------------------------------------------------------------------------------ -------------- ------------ ------------ Cash Flows From Operating Activities: Net income $250 $179 $223 Adjustments to reconcile net income to net cash provided from operating activities: Cumulative effect of accounting change, net of taxes (29) - - Depreciation and amortization 227 177 152 Amortization of nuclear fuel 16 18 20 Gain on sale of subsidiary assets (3) (68) - Equity in losses of affiliates 3 1 - Preferred stock dividends 7 7 8 Allowance for funds used during construction (9) (7) (16) Over (under) collection, fuel adjustment clauses (33) (6) 1 Changes in certain assets and liabilities: Increase in receivables (263) (42) (28) Increase in deferred income taxes, net 61 19 15 Increase in pension asset (43) (29) (33) Increase in postretirement benefits 15 11 26 Decrease in other regulatory assets 4 19 16 Increase (decrease) in other regulatory liabilities 11 (7) 4 (Increase) decrease in inventories 3 (14) (16) Increase (decrease) in accounts payable 157 (30) 88 Increase (decrease) in taxes accrued (55) 14 13 Other, net 72 (17) (6) ------------------------------------------------------------------------------ -------------- ------------ ------------ Net Cash Provided From Operating Activities 391 225 467 ------------------------------------------------------------------------------ -------------- ------------ ------------ Cash Flows From Investing Activities: Utility property additions and construction expenditures, net of AFC (334) (238) (281) Purchase of subsidiary, net of cash acquired (212) - - Proceeds on sale of subsidiary assets 8 112 - Increase in nonutility property and investments, net: Nonutility property (27) (23) (22) Investments (20) (74) (106) ------------------------------------------------------------------------------ -------------- ------------ ------------ Net Cash Used For Investing Activities (585) (223) (409) ------------------------------------------------------------------------------ -------------- ------------ ------------ Cash Flows From Financing Activities: Proceeds: Issuance of First Mortgage Bonds 148 99 - Issuance of notes and loans 998 200 249 Repayments and repurchases: Mortgage bonds (100) (10) (50) Notes and loans (175) (77) (96) Other long-term debt (8) (10) - Preferred stock (1) - (1) Common stock (488) - (110) Dividend payments: Common Stock (124) (148) (162) Preferred stock (7) (7) (8) Short-term borrowings, net (6) 71 136 Fuel financings, net - (66) (14) ------------------------------------------------------------------------------ -------------- ------------ ------------ Net Cash Provided From (Used For) Financing Activities 237 52 (56) ------------------------------------------------------------------------------ -------------- ------------ ------------ Net Increase in Cash and Temporary Cash Investments 43 54 2 Cash and Temporary Cash Investments, January 1 116 62 60 ============================================================================== ============== ============ ============ Cash and Temporary Cash Investments, December 31 $159 $116 $ 62 ============================================================================== ============== ============ ============ Supplemental Cash Flow Information: Cash paid for - Interest (net of capitalized interest of $6, $4 and $7) $207 $138 $120 - Income taxes 139 84 114 Noncash Investing and Financing Activities: Unrealized gain (loss) on securities available for sale, net of tax (197) 311 7 In conjunction with the acquisition of Public Service Company of North Carolina, Incorporated, liabilities were assumed as follows: Fair value of assets acquired $1,177 Cash paid for capital stock (212) Stock issued as consideration (488) --------- Liabilities assumed $477 See Notes to Consolidated Financial Statements. SCANA Corporation CONSOLIDATED STATEMENTS OF CAPITALIZATION --------------------------------------------------------------------------------- ------------- ------ ------------- ------ December 31, (Millions of dollars) 2000 1999 --------------------------------------------------------------------------------- ------------- ------ ------------- ------ Common Equity (Note 9): Common stock, without par value, authorized 150,000,000 shares; issued and outstanding, 104,729,131 shares in 2000 and 103,572,623 shares in 1999 $1,043 $1,043 Unrealized gain on securities available for sale, net of taxes 139 336 Retained earnings 850 720 --------------------------------------------------------------------------------- ------------- ------ ------------- ------ Total Common Equity 2,032 40% 2,099 55% --------------------------------------------------------------------------------- ------------- ------ ------------- ------ South Carolina Electric & Gas Company: Cumulative Preferred Stock (Not subject to purchase or sinking funds): $100 Par Value - Authorized 1,200,000 shares $50 Par Value - Authorized 125,209 shares Shares Outstanding Redemption Price Series 2000 1999 ------ ---- ---- $100 Par 6.52% 1,000,000 1,000,000 100.00 100 100 $50 Par 5.00% 125,209 125,209 52.50 6 6 --------------------------------------------------------------------------------- ------------- ------ ------------- ------ Total Preferred Stock (Not subject to purchase or sinking funds) (Note 10) 106 2% 106 3% --------------------------------------------------------------------------------- ------------- ------ ------------- ------ South Carolina Electric & Gas Company: Cumulative Preferred Stock (Subject to purchase and sinking funds): $100 Par Value - Authorized 1,550,000 shares; None outstanding in 2000 and 1999 $50 Par Value - Authorized 1,560,287 shares Shares Outstanding Redemption Price Series 2000 1999 ------ ---- ---- 4.50% 9,600 11,200 51.00 1 1 4.60% (A) 16,052 18,052 51.00 1 1 4.60% (B) 57,800 61,200 50.50 3 3 5.125% 67,000 68,000 51.00 3 3 6.00% 69,835 73,035 50.50 3 4 --------- ------------ Total 220,287 231,487 ========= ============ $25 Par Value - Authorized 2,000,000 shares; None outstanding in 2000 and 1999 ---------------------------------------------------------------------------------- ------------ -------- ----------- ------- Total Preferred Stock (Subject to purchase or sinking funds) 11 12 Less: Current portion, including sinking fund requirements (1) (1) ---------------------------------------------------------------------------------- ------------ -------- ----------- ------- Total Preferred Stock, Net (Subject to purchase or sinking funds) (Notes 10 & 12) 10 -% 11 -% ---------------------------------------------------------------------------------- ------------ -------- ----------- ------- SCE&G-Obligated Mandatorily Redeemable Preferred Securities of SCE&G's Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount of 7.55% Junior Subordinated Debentures of SCE&G, due 2027 (Note 10) 50 1% 50 1% ---------------------------------------------------------------------------------- ------------ -------- ----------- ------- -------------------------------------------------------------------- -- -------------- -------- -------------- ----------- December 31, (Millions of dollars) 2000 1999 -------------------------------------------------------------------- -- -------------- -------- -------------- ----------- Long-Term Debt (Notes 6 & 12) SCANA Corporation: Medium-Term Notes: Series Year of Maturity 5.52% 2000 - 150 6.15% 2000 - 20 7.45% 2002 300 - 5.91%(1) 2002 400 - 6.51% 2003 20 20 6.05% 2003 60 60 6.25% 2003 75 75 7.44% 2004 50 50 6.90% 2007 25 25 5.81% 2008 115 115 (1) Current rate, based on LIBOR, reset quarterly Bank note, due 2002-2003, LIBOR rate, reset 1, 2, 3 or 6 months, currently 6.57% 300 - South Carolina Electric & Gas Company: First Mortgage Bonds: Series Year of Maturity 6% 2000 - 100 6 1/4% 2003 100 100 7.70% 2004 100 100 7 1/2% 2005 150 - 6 1/8% 2009 100 100 7 1/8% 2013 150 150 7 1/2% 2023 150 150 7 5/8% 2023 100 100 7 5/8% 2025 100 100 First and Refunding Mortgage Bonds: Series Year of Maturity 9% 2006 131 131 8 7/8% 2021 103 103 Pollution Control Facilities Revenue Bonds: Fairfield County Series 1984, due 2014 (6.50%) 57 57 Orangeburg County Series 1994, due 2024 (5.70%) 30 30 Other 17 17 Charleston Franchise Agreement due 1997-2002 7 11 South Carolina Generating Company, Inc.: Berkeley County Pollution Control Facilities Revenue Bonds, Series 1984 due 2014 (6.50%) 36 36 Note, 7.78%, due 2011 49 49 Public Service Company of North Carolina, Incorporated: Senior Debentures: Series Year of Maturity 10% 2004 17 - 8.75% 2012 32 - 6.99% 2026 50 - 7.45% 2026 50 - South Carolina Pipeline Corporation Notes, 6.72%, due 2013 16 17 Other 4 3 -------------------------------------------------------------------- -- -------------- -------- -------------- ----------- Total Long-Term Debt 2,894 1,869 Less - Current maturities, including sinking fund requirements (41) (303) - Unamortized discount (3) (3) -------------------------------------------------------------------- -- -------------- -------- -------------- ----------- Total Long-Term Debt, Net 2,850 57% 1,563 41% -------------------------------------------------------------------- -- -------------- -------- -------------- ----------- Total Capitalization $5,048 100% $3,829 100% ==================================================================== == ============== ======== ============== =========== See Notes to Consolidated Financial Statements. SCANA Corporation CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY ----------------- ------------- -- --------- ------------------ ------------- ---------------- ----------- -------------- For the Years Ended December 31, 2000 1999 1998 ------------------------------- -- ---------------------------- ------------------------------ -------------------------- (Millions of dollars) Common Comprehensive Common Comprehensive Common Comprehensive Equity Income Equity Income Equity Income ----------------- ------------- -- ----------- ---------------- ------------- ---------------- ----------- -------------- Retained Earnings: Balance at January 1 $720 $678 $617 Net Income 250 $250 179 $179 223 $223 Dividends declared on common stock (120) (137) (162) ---------------------------------- ----------- ---------------- ------------- ---------------- ----------- -------------- Balance at December 31 850 720 678 ------------------------------- -- ----------- ---------------- ------------- ---------------- ----------- -------------- Accumulated other comprehensive income: Balance at January 1 336 25 18 Unrealized gains (losses) on securities, net of taxes ($(106), $165 and $4 in 2000, 1999 and 1998, respectively) (197) (197) 311 311 7 7 ------------------------------- -- ----------- ---------------- ------------- ---------------- ----------- -------------- Comprehensive income $53 $490 $230 ------------------------------- -- ----------- ---------------- ------------- ---------------- ----------- -------------- Balance at December 31 139 336 25 ----------------- ------------- -- ----------- ---------------- ------------- ---------------- ----------- -------------- Common Stock: Balance at January 1 1,043 1,043 1,153 Shares issued 488 - - Shares repurchased (488) - (110) ----------------- ------------- -- ----------- ---------------- ------------- ---------------- ----------- -------------- Balance at December 31 1,043 1,043 1,043 ----------------- ------------- -- ----------- ---------------- ------------- ---------------- ----------- -------------- Total Common Equity $2,032 $2,099 $1,746 ================= ============= == =========== ================ ============= ================ =========== ============== Accumulated other comprehensive income at December 31, 2000, 1999 and 1998 was comprised of unrealized holding gains and losses on securities, net of taxes. There were no realized gains or losses from these securities for the years ended December 31, 2000, 1999 and 1998. See Notes to Consolidated Financial Statements. 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 registered public utility holding company within the meaning of the Public Utility Holding Company Act of 1935 (PUHCA). The Company, through wholly owned subsidiaries, is engaged predominately in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia. The Company is also engaged in other energy-related businesses. The Company has investments in telecommunications companies and provides fiber optic communications in South Carolina. The accompanying Consolidated Financial Statements reflect the accounts of the Company and its wholly owned subsidiaries: Regulated utilities Nonregulated businesses South Carolina Electric & Gas Company (SCE&G) SCANA Energy Marketing, Inc. South Carolina Fuel Company, Inc. (Fuel Company) SCANA Communications, Inc. (SCI) South Carolina Generating Company, Inc. (GENCO) ServiceCare, Inc. South Carolina Pipeline Corporation Primesouth, Inc. (Pipeline Corporation) SCANA Resources, Inc. Public Service Company of North Carolina, SCANA Services, Inc. Incorporated (PSNC) SCANA Propane Gas, Inc. (in liquidation) SCANA Propane Services, Inc. (in liquidation) SCANA Petroleum Resources, Inc. (in liquidation) SCANA Development Corporation (in liquidation) Certain investments are reported using the cost or equity method of accounting, as appropriate. Significant intercompany balances and transactions have been eliminated in consolidation except as permitted by Statement of Financial Accounting Standards (SFAS) 71 , "Accounting for the Effects of Certain Types of Regulation" which provides that profits on intercompany sales to regulated affiliates are not eliminated if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable. B. Basis of Accounting The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of SFAS 71. This accounting standard requires cost-based rate-regulated utilities to recognize in their financial statements revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result the Company has recorded, as of December 31, 2000, approximately $243 million and $75 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities of approximately $140 million and $57 million, respectively. The electric and gas regulatory assets of approximately $45 million and $58 million, respectively (excluding deferred income tax assets), are recoverable through rates. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company's results of operations in the period the write-off would be recorded, but it is not expected that cash flows or financial position would be materially affected. C. System of Accounts The accounting records of the Company's regulated subsidiaries are maintained in accordance with the Uniform System of Accounts prescribed by either the Federal Energy Regulatory Commission (FERC) or the National Association of Regulatory Utility Commissioners (NARUC) and as adopted by the Public Service Commission of South Carolina (PSC) or, in the case of PSNC, the North Carolina Utilities Commission (NCUC). The NARUC system of accounts is substantially the same as the FERC system of accounts. D. Utility Plant Utility plant is stated substantially at original cost. The costs of additions, renewals and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and an allowance for funds used during construction, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged, along with the cost of removal, less salvage, to accumulated depreciation. The costs of repairs, replacements and renewals of items of property determined to be less than a unit of property are charged to maintenance expense. SCE&G, operator of the V. C. Summer Nuclear Station (Summer Station), and the South Carolina Public Service Authority (Santee Cooper) are joint owners of Summer Station in the proportions of two-thirds and one-third, respectively. The parties share the operating costs and energy output of the plant in these proportions. Each party, however, provides its own financing. Plant-in-service related to SCE&G's portion of Summer Station was approximately $965.0 million and $959.7 million as of December 31, 2000 and 1999, respectively. Accumulated depreciation associated with SCE&G's share of Summer Station was approximately $387.7 million and $365.1 million as of December 31, 2000 and 1999, respectively. SCE&G's share of the direct expenses associated with operating Summer Station is included in "Other operation and maintenance" expenses. E. Allowance for Funds Used During Construction (AFC) AFC, a noncash item, reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company's regulated subsidiaries calculated AFC using composite rates of 8.3%, 8.1% and 8.7% for 2000, 1999 and 1998, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. Interest on nuclear fuel in process is capitalized at the actual interest amount incurred. F. Revenue Recognition Revenues are recorded during the accounting period in which services are provided to customers, and include estimated amounts for electricity and natural gas delivered, but not yet billed. Prior to January 1, 2000 revenues related to regulated electric and gas services were recorded only as customers were billed (see Note 2). Fuel costs for electric generation are collected through the fuel cost component in retail electric rates. The fuel cost component contained in electric rates is established by the PSC during annual fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is deferred and included when determining the fuel cost component during the next annual fuel cost hearing. SCE&G had undercollected through the electric fuel cost component approximately $35.5 million and $10.1 million at December 31, 2000 and 1999, respectively, which are included in "Deferred Debits - Other regulatory assets." 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 costs and amounts contained in rates is deferred and included when establishing gas costs during the next annual gas cost recovery hearing. At December 31, 2000 and 1999 the Company had undercollected through the gas cost recovery procedure approximately $22.0 million and $4.1 million, respectively, which are included in "Deferred Debits Other regulatory assets." SCE&G's and PSNC's gas rate schedules for residential, small commercial and small industrial customers include a weather normalization adjustment, which minimizes fluctuations in gas revenues due to abnormal weather conditions. G. Depreciation and Amortization Provisions for depreciation and amortization are recorded using the straight-line method and are based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were as follows: 2000 1999 1998 ---------------------------------- --------------- --------------- SCE&G 2.98% 2.99% 3.02% GENCO 2.67% 2.56% 2.65% Pipeline Corporation 2.58% 2.62% 2.63% PSNC 4.15% - - Aggregate of Above 3.09% 2.95% 2.98% Nuclear fuel amortization, which is included in "Fuel used in electric generation" and 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 Department of Energy (DOE) under a contract for disposal of spent nuclear fuel. The acquisition adjustment relating to the purchase of certain gas properties in 1982 is being amortized over a 40-year period using the straight-line method. The acquisition adjustment related to the purchase of PSNC in 2000 is being amortized over a 35-year period using the straight-line method. H. Nuclear Decommissioning SCE&G's share of estimated site-specific nuclear decommissioning costs for Summer Station, including the cost of decommissioning plant components not subject to radioactive contamination, totals approximately $357.3 million, stated in 1999 dollars, based on a decommissioning study completed in 2000. Santee Cooper is responsible for decommissioning costs related to its ownership interest in the station. The cost estimate is based on a decommissioning methodology acceptable to the Nuclear Regulatory Commission (NRC) under which the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that permits release for unrestricted use. 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 in each of 2000, 1999 and 1998) are used to pay premiums on insurance policies on the lives of certain Company personnel. SCE&G is the beneficiary of these policies. Through these insurance contracts, SCE&G is able to take advantage of income tax benefits and accrue earnings on the fund on a tax-deferred basis. 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 NRC. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis. SCE&G records its liability for decommissioning costs in deferred credits. In addition to the above, pursuant to the National Energy Policy Act passed by Congress in 1992 and the requirements of the DOE, SCE&G has recorded a liability for its estimated share of the DOE's decontamination and decommissioning obligation. The liability, approximately $2.8 million at December 31, 2000, has been included in "Long-Term Debt, net." SCE&G is recovering the cost associated with this liability through the fuel cost component of its rates; accordingly, this amount has been deferred and is included in "Deferred Debits - Other." I. Income Taxes The Company files a consolidated income tax return. Under a joint consolidated income tax allocation agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant 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. J. 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. K. Environmental The Company maintains an environmental assessment program to identify and assess current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate primarily to regulated operations. Such amounts are deferred and amortized with recovery provided through rates. The Company also has recovered portions of its environmental liabilities through settlements with various insurance carriers, including all amounts previously deferred for its electric operations. The Company expects to recover all deferred amounts related to SCE&G's gas operations by December 2005. Deferred amounts for SCE&G, net of amounts recovered through rates and insurance settlements, totaled $20.2 million and $23.7 million at December 31, 2000 and 1999, respectively. Deferred amounts for PSNC totaled $10.2 million at December 31, 2000. The deferral includes the estimated costs associated with the matters discussed in Note 13C. L. 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. M. Commodity Derivatives To minimize price risk due to market fluctuations, the Company utilizes forward contracts, futures contracts, option contracts and swap agreements to hedge certain purchases and sales of natural gas. Changes in the market value of such financial contracts pertaining to nonregulated operations are deferred and included in income in the period in which the offsetting physical transactions occur. For such transactions related to the Company's regulated operations, gains and losses on these contracts are included as a component of the related cost of gas which is subject to recovery under the fuel adjustment clause. (See Note 1F). The resulting under or over recovery of such costs is recorded in "Deferred Debits" or "Deferred Credits," respectively, on the balance sheet. N. Recently Issued Accounting Standard and Bulletin In June 1998 the Financial Accounting Standards Board (FASB) issued SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." In June 2000, the FASB issued SFAS 138, which amends certain provisions of SFAS 133 to expand the normal purchase and sale exemption for supply contracts and to redefine interest rate risk to reduce sources of ineffectiveness, among other things. The Company utilizes various derivatives in its risk management activities, including swaps and commodities futures. The Company adopted SFAS 133, as amended, on January 1, 2001. As a result of adopting SFAS 133, the Company recorded a credit of approximately $23.0 million, net of tax, as the effect of a change in accounting principle (transition adjustment) to other comprehensive income on January 1, 2001. This amount represents the reclassification of unrealized gains that were deferred and reported as liabilities at December 31, 2000. In the future, all gains/losses related to qualifying cash flow hedges deferred in other comprehensive income will be reclassified to earnings at the time the hedged transaction affects earnings. In December 1999 Staff Accounting Bulletin No. 101, "Revenue Recognition in Financial Statements" was issued by the Securities and Exchange Commission (SEC), and provides the SEC staff's views in applying generally accepted accounting principles to selected revenue recognition issues. The Company's adoption of this bulletin in the fourth quarter of 2000 had no impact on its results of operations, cash flows or financial position. O. Stock Option Plan On April 27, 2000 the Company adopted the SCANA Corporation Long-Term Equity Compensation Plan (the Plan). Under the Plan, certain employees and non-employee directors may receive nonqualified stock options and other forms of equity compensation. The Company accounts for this equity-based compensation under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25). In addition the Company has adopted the disclosure provisions of SFAS 123, "Accounting for Stock-Based Compensation." P. Earnings Per Share Earnings per share amounts have been computed in accordance with SFAS 128, "Earnings Per Share." Under SFAS 128, basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share are computed as net income divided by the weighted average number of shares of common stock outstanding during the period after giving effect to securities considered to be dilutive potential common stock. The Company uses the treasury stock method in determining total dilutive potential common stock. Q. Reclassifications Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2000. R. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. 2. Cumulative Effect of Accounting Change Effective January 1, 2000 the Company changed its method of accounting for operating revenues associated with its regulated utility operations from cycle billing to full accrual. The cumulative effect of this change was $29 million, net of tax. Accruing unbilled revenues more closely matches revenues and expenses. Unbilled revenues represent the estimated amount customers will be charged for service rendered but not yet billed as of the end of the accounting period. If this method had been applied retroactively, net income would have been $181 million ($1.75 per share) and $216 million ($2.05 per share) for the years ended December 31, 1999 and 1998, respectively, compared to $179 million ($1.73 per share) and $223 million ($2.12 per share), respectively, as reported. 3. ACQUISITION On February 10, 2000 the Company completed its acquisition of PSNC in a business combination accounted for as a purchase. PSNC became a wholly owned subsidiary of the Company. PSNC is a public utility engaged primarily in transporting, distributing and selling natural gas to approximately 370,000 residential, commercial and industrial customers in 25 of its 28 franchised counties in North Carolina. Pursuant to the Agreement and Plan of Merger, PSNC shareholders were paid approximately $212 million in cash and 17.4 million shares of SCANA common stock valued at approximately $488 million. In connection with the acquisition, 16.3 million shares of SCANA common stock were repurchased for approximately $488 million. The results of operations of PSNC are included in the accompanying financial statements as of January 1, 2000, the effective date of acquisition . The total cost of the acquisition was approximately $700 million, which exceeded the fair value of the net assets acquired by approximately $466 million. The excess is being amortized over 35 years on a straight-line basis. The following represents the unaudited pro forma results of operations of the Company for 1999 as if the acquisition were consummated on January 1, 1999. The unaudited pro forma results of operations exclude the effects of the accounting change discussed in Note 2 and include certain pro forma adjustments, including the amortization of the acquisition adjustment and interest on acquisition financing. The unaudited pro forma results of operations do not necessarily reflect the results that would have occurred had the acquisition occurred at January 1, 1999 or the results that may occur in the future. In millions of dollars, except per share amount ----------------------------------------------------------- ------------------ Operating revenues $2,385 Net income 163 Basic and diluted earnings per share 1.56 4. RATE AND OTHER REGULATORY MATTERS South Carolina Electric & Gas Company A. On July 20, 2000 the PSC issued an order approving SCE&G's request for an out-of-period adjustment to increase the cost of gas component of its rates for natural gas service from 54.334 cents per therm to 68.835 cents per therm, effective with the first billing cycle in August 2000. As part of its regularly scheduled annual review of gas costs, the PSC issued an order on November 9, 2000 which further increased the cost of gas component to 78.151 cents per therm, effective with the first billing cycle in November 2000. On December 21, 2000 the PSC issued an order approving SCE&G's request for another out-of-period adjustment to increase the cost of gas component to 99.340 cents per therm, effective with the first billing cycle in January 2001. B. On July 5, 2000 the PSC approved SCE&G's request to implement lower depreciation rates for its gas operations. The new rates were effective retroactively to January 1, 2000 and resulted in a reduction in annual depreciation expense of approximately $2.9 million. C. On September 14, 1999 the PSC approved an accelerated capital recovery plan for SCE&G's Cope Generating Station. The plan was implemented beginning January 1, 2000 for a three-year period. The PSC approved an accelerated capital recovery methodology wherein SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates. The amount of the accelerated depreciation will be determined by SCE&G based on the level of revenues and operating expenses, not to exceed $36 million annually without the approval of the PSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year. As of December 31, 2000, no accelerated depreciation has been recorded. The accelerated capital recovery plan will be accomplished through existing customer rates. D. On December 11, 1998 the PSC issued an order requiring SCE&G to reduce retail electric rates on a prospective basis. The PSC acted in response to SCE&G reporting that it earned a 13.04 percent return on common equity for its retail electric operations for the 12 months ended September 30, 1998. This return on common equity exceeded SCE&G's authorized return of 12.0 percent by 1.04 percent, or $22.7 million, primarily as a result of record heat experienced during the summer. The order required prospective rate reductions on a per kilowatt-hour basis, based on actual retail sales for the 12 months ended September 30, 1998. On January 12, 1999 the PSC denied SCE&G's motion for reconsideration, ruled that no further rate action was required, and reaffirmed SCE&G's authorized return on equity of 12.0 percent. The rate reductions were placed into effect with the first billing cycle of January 1999. E. On January 9, 1996 the PSC issued an order granting SCE&G an increase in retail electric rates which were fully implemented by January 1997. The PSC authorized a return on common equity of 12.0 percent. The PSC also approved establishment of a Storm Damage Reserve Account capped at $50 million to be collected through rates over a ten-year period. Additionally, the PSC approved accelerated recovery of a significant portion of SCE&G's electric regulatory assets (excluding deferred income tax assets) and the remaining transition obligation for postretirement benefits other than pensions, changing the amortization periods to allow recovery by the end of the year 2000. SCE&G's request to shift, for rate-making purposes, approximately $257 million of depreciation reserves from transmission and distribution assets to nuclear production assets was also approved. The Consumer Advocate and two other intervenors appealed certain issues in the order initially to the South Carolina Circuit Court (Circuit Court), which affirmed the PSC's decisions, and, subsequently, to the South Carolina Supreme Court (Supreme Court). In March 1998 SCE&G, the PSC, the Consumer Advocate and one of the other intervenors reached an agreement that provided for the reversal of the shift in depreciation reserves and the dismissal of the appeal of all other issues. The PSC also authorized SCE&G to adjust depreciation rates that had been approved in the 1996 rate order for its electric transmission, distribution and nuclear production properties to eliminate the effect of the depreciation reserve shift and to retroactively apply such depreciation rates to February 1996. As a result, a one-time reduction in depreciation expense of $9.8 million was recorded in March 1998. The agreement does not affect retail electric rates. The FERC had previously rejected the transfer of depreciation reserves for rates subject to its jurisdiction. In September 1998 the Supreme Court affirmed the Circuit Court's rulings on the issues contested by the remaining intervenor. F. In 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 (MGPs). The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for SCE&G's gas operations that had previously been deferred. In November 2000, as a result of the annual review, the PSC approved SCE&G's request to maintain the billing surcharge at $.011 per therm to provide for the recovery of the remaining balance of $20.1 million. G. In September 1992 the PSC issued an order granting SCE&G's request for a $.25 increase in transit fares from $.50 to $.75 in Columbia, 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 in October 1992. SCE&G appealed the PSC's order to the Circuit Court, which in May 1995 ordered the case back to the PSC for reconsideration of several issues including the low income rider program, routing changes, and the $.75 fare. The Supreme Court declined to review an appeal of the Circuit Court decision and dismissed the case. The PSC and other intervenors filed another Petition for Reconsideration, which the Supreme Court denied. The PSC and other intervenors filed another appeal to the Circuit Court which the Circuit Court denied in an order dated May 9, 1996. In this order, the Circuit Court upheld its previous orders and remanded them to the PSC. During August 1996 the PSC heard oral arguments on the orders on remand from the Circuit Court. On September 30, 1996 the PSC issued an order affirming its previous orders and denied SCE&G's request for reconsideration. In response to an appeal of the PSC's order by SCE&G, the Circuit Court issued an order on May 25, 2000, which remanded the matter to the PSC for review of SCE&G's original application and request to terminate the low income rider fare. On September 27, 2000 the PSC issued an order granting the relief requested by SCE&G. On September 29, 2000 the Consumer Advocate filed a motion with the PSC for a stay of this order to which SCE&G filed a response. On October 3, 2000 the PSC accepted the Consumer Advocate's motion and issued a stay of its order. The Consumer Advocate and other intervenors have petitioned the Circuit Court for judicial review of the PSC's order granting relief. Action by the Circuit Court is pending. Public Service Company of North Carolina, Incorporated H. On April 6, 2000 the NCUC issued an order permanently approving PSNC's request to establish its commodity cost of gas for large commercial and industrial customers on the basis of market prices for natural gas. The NCUC previously allowed PSNC use of this mechanism on a trial basis. This procedure allows PSNC to manage its deferred gas costs better by ensuring that the amount paid for natural gas to serve these customers approximates the amount collected from them. I. A state expansion fund, established by the North Carolina General Assembly in 1991 and funded by refunds from PSNC's interstate pipeline transporters, provides financing for expansion into areas that otherwise would not be economically feasible to serve. On December 30, 1999 PSNC filed an application with the NCUC to extend natural gas service to Madison, Jackson and Swain Counties, North Carolina. Pursuant to state statutes, the NCUC required PSNC to forfeit its exclusive franchises to serve six counties in western North Carolina effective January 31, 2000 because these counties were not receiving any natural gas service. Madison, Jackson and Swain Counties were included in the forfeiture order. On June 29, 2000 the NCUC approved PSNC's requests for reinstatement of its exclusive franchises for Madison, Jackson and Swain Counties and disbursement of up to $28.4 million from PSNC's expansion fund for this project. PSNC estimates that the cost of this project will be approximately $31.4 million. J. On December 7, 1999 the NCUC issued an order approving the acquisition of PSNC by the Company. As specified in the NCUC order, PSNC reduced its rates by approximately $1 million in August 2000, will reduce rates another $1 million in August 2001 and has agreed to a five-year moratorium on general rate cases. General rate relief can be obtained during this period to recover costs associated with materially adverse governmental actions and force majeure events. K. On February 22, 1999 the NCUC approved PSNC's application to use expansion funds to extend natural gas service into Alexander County and authorized disbursements from the fund of approximately $4.3 million based upon budgeted construction cost of approximately $6.2 million. Most of Alexander County lies within PSNC's certificated service territory and did not previously have natural gas service. The project was completed and customers began receiving natural gas service in March 2000. L. On October 30, 1998 the NCUC issued an order in PSNC's general rate case filed in April 1998. The order, effective November 1, 1998, granted PSNC additional revenue of $12.4 million and allowed a 9.82 percent overall rate of return on PSNC's net utility investment. It also approved the continuation of the Weather Normalization Adjustment and Rider D Mechanisms and full margin transportation rates. PSNC's Rider D rate mechanism authorizes the recovery of all prudently incurred gas costs from customers on a monthly basis. Any difference in amounts paid and collected for these costs is deferred for subsequent refund to or collection from customers. On February 4, 2000, in response to an appeal by the Carolina Utility Customers Association, Inc., the Supreme Court of North Carolina affirmed the NCUC order. 5. EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN Employee Benefit Plans The Company sponsors a noncontributory defined benefit pension plan, which covers substantially all permanent employees. The Company's policy has been to fund the plan to the extent permitted by the applicable Federal income tax regulations as determined by an independent actuary. Effective July 1, 2000 the Company's pension plan was amended to provide a cash balance formula. With certain exceptions, employees were allowed to either remain under the final average pay formula or elect the cash balance formula. Under the final average pay formula, benefits are based on years of accredited service and the employee's average annual base earnings received during the last three years of employment. Under the cash balance formula, the monthly benefit earned under the final average pay formula at July 1, 2000 was converted to a lump sum amount for each employee and increased by transition credits for eligible employees. Under the cash balance formula, benefits based upon this opening balance increase going forward as a result of compensation credits and interest credits. The effect of this plan amendment was to reduce the Company's net periodic benefit income for the year ended December 31, 2000 by approximately $3.7 million. In addition to pension benefits, the Company provides certain unfunded health care and life insurance benefits to active and retired employees. Retirees share in a portion of their medical care cost. The Company provides life insurance benefits to retirees at no charge. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for the applicable benefits. Additionally, to accelerate the amortization of the remaining transition obligation for postretirement benefits other than pensions, as authorized by the PSC, the Company expensed approximately $0.7 million and $15.7 million for the years ended December 31, 1999 and 1998, respectively. (See Note 4E.) Effective July 1, 2000 PSNC's pension and postretirement benefit plans were merged with SCANA's plans. At the time of the merger of the plans, PSNC had recorded a prepaid pension cost of approximately $9.0 million and a postretirement welfare plan obligation of approximately $9.1 million in its consolidated balance sheet. Disclosures required for these plans under SFAS 132, "Employer's Disclosures about Pensions and Other Postretirement Benefits" are set forth in the following tables: Components of Net Periodic Benefit Cost Retirement Benefits Other Postretirement Benefits -------------------------------------- -------------------------------------- Millions of dollars 2000 1999 1998 2000 1999 1998 ---- ---- ---- ---- ---- ---- Service cost $ 8.3 $10.0 $ 8.3 $ 2.7 $ 3.0 $ 2.6 Interest cost 33.5 27.9 25.9 10.2 9.5 9.4 Expected return on assets (76.6) (65.5) (59.3) n/a n/a n/a Prior service cost amortization 3.0 1.1 1.1 0.8 0.7 0.7 Actuarial (gain) loss (12.2) (8.6) (9.6) - 1.2 1.0 Transition amount amortization 0.8 0.8 0.8 0.8 1.7 19.1 - Special termination benefit cost - 5.5 - 1.0 - ----- --- -- - ---- --- - Net periodic benefit (income) cost $(43.2) $(28.8) $(32.8) $14.5 $17.1 $32.8 ======= ====== ====== ===== ===== ===== Weighted-Average Assumptions Retirement Benefits Other Postretirement Benefits -------------------------------------- -------------------------------------- As of December 31, 2000 1999 1998 2000 1999 1998 ---- ---- ---- ---- ---- ---- Discount rate 8.0% 8.0% 7.0% 8.0% 8.0% 7.0% Expected return on plan assets 9.5% 9.5% 9.5% n/a n/a n/a Rate of compensation increase 4.0% 4.0% 4.0% 4.0% 4.0% 4.0% Changes in Benefit Obligation Retirement Benefits Other Postretirement Benefits ------------------------------ --------------------------------- Millions of dollars 2000 1999 2000 1999 ---- ---- ---- ---- Benefit obligation, January 1 $362.3 $389.3 $129.8 $137.0 Service cost 8.3 10.0 2.7 3.0 Interest cost 33.5 27.9 10.2 9.5 Plan participants' contributions 0.1 0.1 0.5 0.5 Plan amendment 65.4 - 0.9 - Actuarial (gain) loss 1.6 (51.6) (7.8) (14.5) Acquisition/merger of plans 39.8 - 11.2 - Benefits paid (31.7) (18.9) (8.5) (6.7) Special termination benefit cost - 5.5 - 1.0 ----------- ------ --- -- ------ --- Benefit obligation, December 31 $479.3 $362.3 $139.0 $129.8 ====== ====== ====== ====== Change in Plan Assets Retirement Benefits ---------------------------------------------------- Millions of dollars 2000 1999 ---- ---- Fair value of plan assets, January 1 $783.0 $698.8 Actual return on plan assets 96.7 103.0 Company contribution - - Plan participants' contributions 0.1 0.1 Acquisition/merger of plans 46.2 - Benefits paid (31.7) (18.9) ----- ----- Fair value of plan assets, December 31 $894.3 $783.0 ====== ====== Funded Status of Plans Retirement Benefits Other Postretirement Benefits ------------------------ ------------------------------- Millions of dollars 2000 1999 2000 1999 ---- ---- ---- ---- Funded status, December 31 $415.0 $420.7 $(139.0) $(129.8) Unrecognized actuarial (gain) loss (297.6) (294.0) 13.0 18.8 Unrecognized prior service cost 73.7 11.4 4.5 4.3 Unrecognized net transition obligation 4.8 5.6 8.3 9.1 ---------- ------ --- ----- --- ----- --- Net amount recognized in Consolidated Balance Sheet $195.9 $143.7 $(113.2) $(97.6) = ====== ====== ======== ====== Health Care Trends The determination of net periodic other postretirement benefit cost is based on the following assumptions: 2000 1999 1998 ---------------------------------------------------------------- ---------- ---------- ---------- Health care cost trend rate 7.5% 8.0% 8.5% Ultimate health care cost trend rate 5.5% 5.5% 5.0% Year achieved 2005 2005 2005 The effect of a one-percentage-point increase or decrease in the assumed health care cost trend rates on the aggregate of the service and interest cost components of net periodic other postretirement health care benefit cost and the accumulated other postretirement benefit obligation for health care benefits are as follows: Millions of dollars 1% 1% Increase Decrease --------------- ----------------- Effect on health care cost $0.2 $(0.3) Effect on postretirement obligation 2.9 (3.4) Long-Term Equity Compensation Plan The Long-Term Equity Compensation Plan (the Plan) became effective January 1, 2000. The Plan provides for grants of incentive and nonqualified stock options, stock appreciation rights, restricted stock, performance shares and performance units to certain key employees. The Plan currently authorizes the issuance of up to five million shares of the Company's common stock, no more than one million of which may be granted in the form of restricted stock. As of December 31, 2000 only nonqualified stock options had been granted. One-third of the options vest on each anniversary of the date of grant until full vesting occurs in the third year. The options expire ten years after the grant date. At December 31, 2000, no stock options were exercisable, and none were forfeited during the year. A summary of activity related to grants of nonqualified stock options follows: Weighted Number of Average Options Exercise Price ----------------- -------------------- Outstanding - December 31, 1999 - - Granted 160,508 $25.53 ================= ==================== Outstanding - December 31, 2000 160,508 $25.53 ================= ==================== The Company applies the intrinsic value method prescribed by APB 25 and related interpretations in accounting for grants made under the Plan. Because all options were granted with exercise prices equal to the fair market value of the Company's stock on the respective grant dates , no compensation expense has been recognized in connection with such grants. If the Company had determined compensation expense for the issuance of options based on the fair value method described in SFAS 123, "Accounting for Stock-Based Compensation," net income and earnings per share for 2000 would have been reduced to the pro forma amounts presented below: Net income - as reported (millions) $250.4 Net income - pro forma (millions) 250.3 Basic earnings per share and diluted - as reported 2.40 Basic earnings per share and diluted - pro forma 2.40 For purposes of the above pro forma information, the weighted average fair value at grant date (the value at grant date of the right to purchase stock at a fixed price for an extended time period) for options granted in 2000 was $4.43 and was estimated using the Black-Scholes Option pricing model with the following weighted average assumptions. Expected life of options (years) 10 Risk free interest rate 5.99% Volatility of underlying stock 21% Dividend yield of underlying stock 4.4% 6. LONG-TERM DEBT The annual amounts of long-term debt maturities and sinking fund requirements for the years 2001 through 2005 are summarized as follows: Year Amount Year Amount ----------------- ----------------- ------------------ ----------------- (Millions of dollars) 2001 $41.0 2004 $186.3 2002 887.3 2005 182.0 2003 447.5 ----------------- ----------------- ------------------ ----------------- Approximately $23.5 million of the portion of long-term debt payable in 2001 may be satisfied by either deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits, or by deposit of cash with the Trustee. On August 7, 1996 the City of Charleston executed 30-year electric and gas franchise agreements with SCE&G. In consideration for the electric franchise agreement, SCE&G is paying the City $25 million over seven years (1996-2002) and has donated to the City the existing transit assets in Charleston. The $25 million is included in electric plant-in-service. In settlement of environmental claims the City may have had against SCE&G involving the Calhoun Park area, where SCE&G and its predecessor companies operated a MGP until the 1960's, SCE&G paid the City $26 million over a four-year period (1996-1999). SCE&G has three-year revolving lines of credit totaling $75 million, in addition to other lines of credit, that provide liquidity for issuance of commercial paper. The three-year lines of credit provide back-up liquidity when commercial paper outstanding is in excess of $175 million. The long-term nature of the lines of credit allow commercial paper in excess of $175 million to be classified as long-term debt. SCE&G's commercial paper outstanding totaled $117.5 million and $143.1 million at December 31, 2000 and 1999, at weighted average interest rates of 6.59 percent and 6.63 percent, respectively. Substantially all utility plant is pledged as collateral in connection with long-term debt. The Company has a $300 million credit agreement with banks. At December 31, 2000 the entire amount was outstanding. 7. FUEL FINANCINGS Nuclear and fossil fuel inventories and sulfur dioxide emission allowances are financed through the issuance by Fuel Company of short-term commercial paper. These short-term borrowings are supported by a 364-day revolving credit agreement which expires December 19, 2001. The credit agreement provides for a maximum amount of $125 million to be outstanding at any time. Since the credit agreement expires within one year, commercial paper amounts outstanding have been classified as short-term debt. Commercial paper outstanding totaled $70.2 million at December 31, 2000 and 1999, at weighted average interest rates of 6.59 percent and 6.44 percent, respectively. 8. SHORT-TERM BORROWINGS The Company pays fees to banks as compensation for its committed lines of credit. Commercial paper borrowings are for 270 days or less. Details of lines of credit (including uncommitted lines of credit) and short-term borrowings, excluding amounts classified as long-term (Note 6), at December 31, 2000 and 1999, are as follows: Millions of dollars 2000 1999 -------------------------------------------------------------- --------------- Authorized lines of credit at year-end $649.0 $558.3 Unused lines of credit at year-end $564.0 $505.0 Short-term borrowings outstanding at year-end: Bank loans $85.0 $53.2 Weighted average interest rate 7.48% 7.80% Commercial paper $312.7 $213.3 Weighted average interest rate 6.63% 6.63% 9. COMMON EQUITY The changes in "Common Stock," without par value, during 2000, 1999 and 1998 are summarized as follows: Number of Shares Millions of Dollars ----------------------------------------------------------------------------- Balance at December 31, 1997 107,321,113 $1,152.9 Repurchase of common stock (3,748,490) (110.0) ----------------------------------------------------------------------------- Balance at December 31, 1998 103,572,623 1,042.9 Changes in common stock - - ----------------------------------------------------------------------------- Balance at December 31, 1999 103,572,623 1,042.9 Issuance of common stock 17,413,011 487.7 Repurchase of common stock (16,256,503) (487.7) ----------------------------------------------------------------------------- Balance at December 31, 2000 104,729,131 $1,042.9 ============================================================================= 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, under certain circumstances, could limit the payment of cash dividends on its common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2000 approximately $32.7 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G's common stock. Cash dividends on common stock were declared during 2000, 1999 and 1998 at an annual rate per share of $1.15, $1.32 and $1.54, respectively. 10. PREFERRED STOCK The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend. Retirements under sinking fund requirements are at par values. The aggregate annual amount of purchase fund or sinking fund requirements for preferred stock for the years 2001 through 2005 is $2.8 million. The changes in "Total Preferred Stock (Subject to purchase or sinking funds)" during 2000, 1999 and 1998 are summarized as follows: Number of Shares Millions of Dollars --------------------------------------------------------- ---------------------- Balance at December 31, 1997 251,094 $12.5 Shares Redeemed - $50 par value (11,042) (0.5) --------------------------------------------------------- ---------------------- Balance at December 31, 1998 240,052 12.0 Shares Redeemed - $50 par value (8,565) (0.4) --------------------------------------------------------- ---------------------- Balance at December 31, 1999 231,487 11.6 Shares Redeemed - $50 par value (11,200) (0.6) --------------------------------------------------------- ---------------------- Balance at December 31, 2000 220,287 $11.0 ========================================================= ====================== On October 28, 1997 SCE&G Trust I (the "Trust"), a wholly owned subsidiary of SCE&G, issued $50 million (2,000,000 shares) of 7.55 percent Trust Preferred Securities, Series A (the "Preferred Securities"). SCE&G owns all of the Common Securities of the Trust (the "Common Securities"). The Preferred Securities and the Common Securities (the "Trust Securities") represent undivided beneficial ownership interests in the assets of the Trust. The Trust exists for the sole purpose of issuing the Trust Securities and using the proceeds thereof to purchase from SCE&G its 7.55 percent Junior Subordinated Debentures due September 30, 2027. The sole asset of the Trust is $50.0 million of Junior Subordinated Debentures of SCE&G. Accordingly, no financial statements of the Trust are presented. SCE&G's obligations under the Guarantee Agreement entered into in connection with the Preferred Securities, when taken together with SCE&G's obligation to make interest and other payments on the Junior Subordinated Debentures issued to the Trust and SCE&G's obligations under the Indenture pursuant to which the Junior Subordinated Debentures were issued, provides a full and unconditional guarantee by SCE&G of the Trust's obligations under the Preferred Securities. Proceeds were used to redeem preferred stock of SCE&G. The preferred securities of the Trust are redeemable only in conjunction with the redemption of the related 7.55 percent Junior Subordinated Debentures. The Junior Subordinated Debentures will mature on September 30, 2027 and may be redeemed, in whole or in part, at any time on or after September 30, 2002 or upon the occurrence of a Tax Event. A Tax Event occurs if an opinion is received from counsel experienced in such matters that there is more than an insubstantial risk that: (1) the Trust is or will be subject to Federal income tax, with respect to income received or accrued on the Junior Subordinated Debentures, (2) interest payable by SCE&G on the Junior Subordinated Debentures will not be deductible, in whole or in part, by SCE&G for Federal income tax purposes, or (3) the Trust will be subject to more than a de minimis amount of other taxes, duties, or other governmental charges. Upon the redemption of the Junior Subordinated Debentures, payment will simultaneously be applied to redeem Preferred Securities having an aggregate liquidation amount equal to the aggregate principal amount of the Junior Subordinated Debentures. The Preferred Securities are redeemable at $25 per preferred security plus accrued distributions. 11. INCOME TAXES Total income tax expense attributable to income before cumulative effect of accounting change for 2000, 1999 and 1998 is as follows: Millions of dollars 2000 1999 1998 ----------------------------------------------------------------------- -------- Current taxes: Federal $88.2 $94.5 $114.8 State 9.2 0.6 2.2 ----------------------------------------------------------------------- -------- ----------------------------------------------------------------------- -------- Total current taxes 97.4 95.1 117.0 ----------------------------------------------------------------------- -------- ----------------------------------------------------------------------- -------- Deferred taxes, net: Federal 29.8 6.1 2.3 State 4.7 1.5 2.0 ----------------------------------------------------------------------- -------- ----------------------------------------------------------------------- -------- Total deferred taxes 34.5 7.6 4.3 ----------------------------------------------------------------------- -------- ----------------------------------------------------------------------- -------- Investment tax credits: Deferred - State 5.0 13.4 14.3 Amortization of amounts deferred - State (1.3) (1.2) (0.9) Amortization of amounts deferred - Federal (4.0) (3.6) (3.6) ----------------------------------------------------------------------- -------- Total investment tax credits (0.3) 8.6 9.8 ----------------------------------------------------------------------- -------- Non-conventional fuel tax credits: Deferred - Federal 9.4 n/a n/a ----------------------------------------------------------------------- -------- Total income tax expense $141.0 $111.3 $131.1 ======================================================================= ======== The difference between actual income tax expense and the amount calculated from the application of the statutory Federal income tax rate (35% for 2000, 1999 and 1998) to pre-tax income before cumulative effect of accounting change is reconciled as follows: Millions of dollars 2000 1999 1998 --------------------------------------------------------------- ----------------- ----------------- ----------------- Income before cumulative effect of accounting change $221.6 $179.0 $223.4 Total income tax expense: Charged to operating expense 152.0 112.9 136.2 Credited to other items (11.0) (1.6) (5.1) Preferred stock dividends 7.4 7.4 7.5 --------------------------------------------------------------- ----------------- ----------------- ----------------- =============================================================== ================= ================= ================= Total pre-tax income $370.0 $297.7 $362.0 =============================================================== ================= ================= ================= =============================================================== ================= ================= ================= Income taxes on above at statutory Federal income tax rate $129.5 $104.2 $126.7 Increases (decreases) attributed to: State income taxes (less Federal income tax effect) 11.4 9.3 11.4 Non-deductible book amortization of acquisition adjustments 5.0 0.4 0.4 Amortization of Federal investment tax credits (4.0) (3.6) (3.6) Other differences, net (0.9) 1.0 (3.8) --------------------------------------------------------------- ----------------- ----------------- ----------------- =============================================================== ================= ================= ================= Total income tax expense $141.0 $111.3 $131.1 =============================================================== ================= ================= ================= The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $819.2 million at December 31, 2000 and $789.2 million at December 31, 1999 (see Note 1I), are as follows: Millions of dollars 2000 1999 --------------------------------------------- ---------------- ----------------- Deferred tax assets: Unamortized investment tax credits $63.0 $62.8 Other postretirement benefits 40.6 36.6 Early retirement programs 14.6 14.8 Deferred compensation 8.8 8.8 Cycle billing - 15.5 Other 27.4 19.0 --------------------------------------------- ---------------- ----------------- Total deferred tax assets 154.4 157.5 --------------------------------------------- ---------------- ----------------- Deferred tax liabilities: Property, plant and equipment 765.5 665.4 Investments in equity securities 80.0 184.7 Pension plan benefit income 65.3 50.7 Research and experimentation costs 26.8 27.3 Deferred fuel costs 18.5 5.5 Cycle billing 1.9 - Other 15.6 13.1 --------------------------------------------- ---------------- ----------------- Total deferred tax liabilities 973.6 946.7 --------------------------------------------- ---------------- ----------------- Net deferred tax liability $819.2 $789.2 ============================================= ================ ================= The Internal Revenue Service has examined and closed consolidated Federal income tax returns of the Company through 1995, has examined and proposed adjustments to the Company's 1996 and 1997 Federal returns, and is currently examining the Company's Federal returns for 1998 and 1999. The Company does not anticipate that any adjustments which might result from these examinations will have a significant impact on its results of operations, cash flows or financial position. 12. FINANCIAL INSTRUMENTS The carrying amounts and estimated fair values of the Company's financial instruments at December 31, 2000 and 1999 are as follows: Millions of dollars 2000 1999 --------------------------------------------------------- ----------------------------- ----------------------------- Estimated Estimated Carrying Fair Carrying Fair Amount Value Amount Value --------------------------------------------------------- -------------- -------------- -------------- -------------- Assets: Cash and temporary cash investments $158.7 $158.7 $116.0 $116.0 Investments 681.7 1,234.5 941.8 1,952.4 Liabilities: Short-term borrowings 397.7 397.7 266.5 266.5 Long-term debt 2,890.5 2,931.9 1,865.8 1,830.7 Preferred stock (subject to purchase or sinking funds) 11.0 8.7 11.6 8.5 The information presented herein is based on pertinent available information as of December 31, 2000 and 1999. 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, 2000, 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: o Cash and temporary cash investments, including commercial paper, repurchase agreements, treasury bills and notes, are valued at their carrying amount. o Fair values of investments and long-term debt are based on quoted market prices of the instruments or similar instruments. For debt instruments for which there are no quoted market prices available, fair values are based on net present value calculations. For investments for which the fair value is not readily determinable, fair value approximates cost. Settlement of long-term debt may not be possible or may not be considered prudent. o Short-term borrowings are valued at their carrying amount. o The fair value of preferred stock (subject to purchase or sinking funds) is estimated on the basis of market prices. At December 31, 2000, SCANA Communications Holdings, Inc. (SCH), a wholly owned, indirect subsidiary of SCANA, held the following investments in ITC Holding Company, Inc. (ITC) and its affiliates: o Powertel, Inc. (Powertel) is a publicly traded company that owns and operates personal communications services (PCS) systems in several major Southeastern markets. SCH owns approximately 4.9 million common shares of Powertel at a cost of approximately $77.7 million. Powertel common stock closed at $61.9375 per share on December 31, 2000, resulting in a pre-tax unrealized holding gain of $228.8 million (a decline of $189.0 million from December 31, 1999). Accumulated other comprehensive income includes the after-tax amount of all unrealized holding gains and losses on common shares. In addition, SCH owns the following series of non-voting convertible preferred shares, at the approximate cost noted: 100,000 shares series B ($75.1 million); 50,000 shares series D ($22.5 million); and 50,000 shares 6.5 percent series E ($75.0 million). Cumulative dividends on preferred series E shares are generally paid in common shares of Powertel and are accrued quarterly. Preferred series B shares become convertible in March 2002 at a conversion price of $16.50 per common share or approximately 4.6 million common shares. Preferred series D shares become convertible in March 2002 at a conversion price of $12.75 per common share or approximately 1.7 million common shares. Preferred series E shares become convertible in June 2003 at a conversion price of $22.01 per common share or approximately 3.4 million common shares. The market value of the convertible preferred shares of Powertel is not readily determinable. However, as converted, the market value of the underlying common shares for the preferred shares was approximately $606.9 million at December 31, 2000, reflecting an unrecorded pre-tax holding gain of $434.3 million (a decline of $368.4 million from December 31, 1999). On August 28, 2000 SCH announced that under terms of separate definitive agreements, Powertel has agreed to be acquired by either Deutsche Telekom AG or VoiceStream Wireless Corporation (VoiceStream). If Deutsche Telekom's previously announced acquisition of VoiceStream is successfully completed, then Deutsche Telekom would also acquire Powertel. If the Deutsche Telekom - VoiceStream transaction is not completed, then VoiceStream would acquire Powertel. In connection with these transactions, SCH entered into stockholder agreements with each of Deutsche Telekom and VoiceStream pursuant to which SCH agreed to vote its Powertel shares in support of either of these transactions. In addition, SCH agreed to certain restrictions on disposition of its Powertel shares and the shares it would receive in either of these transactions. On March 13, 2001 Powertel shareholders approved the acquisition agreements. o ITC^DeltaCom, Inc. (ITCD) is a fiber optic telecommunications provider. SCH owns approximately 5.1 million common shares of ITCD at a cost of approximately $43.0 million. ITCD common stock closed at $5.39 per share on December 31, 2000, resulting in an unrealized pre-tax holding loss of $15.4 million (a decline of $113.7 million from December 31, 1999). Accumulated other comprehensive income includes the after-tax amount of all unrealized holding gains and losses on common shares. In addition, SCH owns 1,480,771 shares of series A preferred stock of ITCD at a cost of approximately $11.2 million. Series A preferred shares become convertible in March 2002 into 2,961,542 shares of ITCD common stock. The market value of series A preferred stock of ITCD is not readily determinable. However, as converted, the market value of the underlying common stock for the series A preferred stock was approximately $16.0 million at December 31, 2000, reflecting an unrecorded pre-tax holding gain of $4.8 million (a decline of $65.8 million from December 31, 1999). o Knology, Inc. (Knology) is a broad-band service provider of cable television, telephone and internet services. SCH owns $71,050,000 face amount of 11.875 percent Senior Discount Notes due 2007 of Knology Broadband, Inc., a wholly-owned subsidiary of Knology. The Senior Discount Notes have a book basis at December 31, 2000 of approximately $57.9 million. In addition, SCH owns approximately 7.2 million shares of Knology Series A Convertible Preferred Stock with a cost basis of approximately $5.0 million and warrants to purchase approximately 0.2 million shares of Series A Convertible Preferred Stock. On January 12, 2001 SCH invested $25.0 million for approximately 8.3 million shares of Series C Convertible Preferred Stock of Knology. The market value of these investments is not readily determinable. o ITC holds ownership interests in several Southeastern communications companies, including those discussed above. SCH owns approximately 3.1 million common shares, 645,153 series A convertible preferred shares, and 133,664 series B convertible preferred shares of ITC. These investments cost approximately $5.8 million, $7.2 million, and $4.0 million, respectively. The market values of these investments are not readily determinable. 13. COMMITMENTS AND CONTINGENCIES A. Lake Murray Dam Reinforcement On October 15, 1999 FERC notified SCE&G of its agreement with SCE&G's plan to reinforce Lake Murray Dam in order to maintain the lake in case of an extreme earthquake. SCE&G and FERC have been discussing possible reinforcement alternatives for the dam over the past several years as part of SCE&G's ongoing hydroelectric operating license with FERC. Until discussions are concluded, it is not possible to finalize the cost of the project; however, it is possible that the cost could range up to $250 million. Although any costs incurred by SCE&G are expected to be recoverable through electric rates, SCE&G also is exploring alternative sources of funding. The project is expected to be completed in 2004. 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 $9.5 billion. Each reactor licensee is currently liable for up to $88.1 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 $58.7 million per incident, but not more than $6.7 million per year. SCE&G currently maintains policies (for itself and on behalf of Santee Cooper) with Nuclear Electric Insurance Limited (NEIL). The policies covering the nuclear facility for property damage, excess property damage and outage cost permit assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $8.1 million. To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that 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 material adverse impact on the Company's results of operations, cash flows and financial position. C. Environmental South Carolina Electric & Gas Company 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 encompasses approximately 30 acres and includes properties which were locations for industrial operations, including a wood preserving (creosote) plant, one of SCE&G's decommissioned MGPs, properties owned by the National Park Service and the City of Charleston, and private properties. The site has not been placed on the National Priorities List, but may be added in the future. The Potentially Responsible Parties (PRPs) negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study and a corresponding Scope of Work. Field work began in November 1993, and the EPA approved a Remedial Investigation Report in February 1997 and a Feasibility Study Report in June 1998. In July 1998 the EPA approved SCE&G's Removal Action Work Plan for soil excavation. SCE&G completed Phase One of the Removal Action Work Plan in 1998 at a cost of approximately $1.5 million. Phase Two, which cost approximately $3.5 million, included excavation and installation of several permanent barriers to mitigate coal tar seepage. On September 30, 1998 a Record of Decision was issued which sets forth the EPA's view of the extent of each PRP's responsibility for site contamination and the level to which the site must be remediated. SCE&G estimates that the Record of Decision will result in costs of approximately $13.3 million, of which approximately $2 million remains. On January 13, 1999 the EPA issued a Unilateral Administrative Order for Remedial Design and Remedial Action directing SCE&G to design and carry out a plan of remediation for the Calhoun Park site. SCE&G submitted a Comprehensive Remedial Design Work Plan (RDWP) on December 17, 1999 and proceeded with implementation pending agency approval. The RDWP was approved by the EPA in July 2000, and its implementation continues. In October 1996 the City of Charleston and SCE&G settled all environmental claims the City may have had against SCE&G involving the Calhoun Park area for a payment of $26 million over four years (1996-1999) by SCE&G to the City. SCE&G is recovering the amount of the settlement, which does not encompass site assessment and cleanup costs, through rates in the same manner as other amounts accrued for site assessments and cleanup as discussed above. As part of the environmental settlement, SCE&G constructed an 1,100 space parking garage on the Calhoun Park site (construction was completed in April 2000) and transferred the facility to the City in exchange for a $16.5 million, 18-year municipal bond collateralized by revenues from, and a mortgage on, the parking garage. SCE&G owns three other decommissioned MGP sites which contain residues of by-product chemicals. For the site located in Sumter, South Carolina, effective September 15, 1998, SCE&G entered into a Remedial Action Plan Contract with DHEC pursuant to which it agreed to undertake a full site investigation and remediation under the oversight of DHEC. Site investigation and characterization are proceeding according to schedule. Upon selection and successful implementation of a site remedy, DHEC will give SCE&G a Certificate of Completion, and a covenant not to sue. For the site located in Florence, South Carolina, SCE&G entered into a similar Remedial Action Plan Contract with DHEC effective September 5, 2000. SCE&G is continuing to investigate the remaining site in Columbia, and is monitoring the nature and extent of residual contamination. Public Service Company of North Carolina, Incorporated PSNC owns, or has owned, all or portions of seven sites in North Carolina on which MGPs were formerly operated. Intrusive investigation (including drilling, sampling and analysis) has begun at only one site, and the remaining sites have been evaluated using historical records and observations of current site conditions. These evaluations have revealed that MGP residuals are present or suspected at several of the sites. The North Carolina Department of Environment and Natural Resources has recommended that no further action be taken with respect to one site. An environmental due diligence review of PSNC conducted in February 1999 estimated that the cost to remediate the remaining sites would range between $11.3 million and $21.9 million. During the second quarter of 2000, the review was finalized and the estimated liability was recorded. PSNC is unable to determine the rate at which costs may be incurred over this time period. The estimated cost range has not been discounted to present value. PSNC's associated actual costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. An order of the NCUC dated May 11, 1993 authorized deferral accounting for all costs associated with the investigation and remediation of MGP sites. As of December 31, 2000, PSNC has recorded a liability and associated regulatory asset of $10.2 million, which reflects the minimum amount of the range, net of shared cost recovery from other PRPs. Amounts incurred to date are not material. Management intends to request recovery of additional MGP cleanup costs not recovered from other PRPs in future rate case filings, and believes that all costs incurred will be recoverable in gas rates. D. Franchise Agreement See Note 6 for a discussion of the electric franchise agreement between SCE&G and the City of Charleston. E. Claims and Litigation The Company and Westvaco each own a 50 percent interest in Cogen South LLC (Cogen). Cogen was formed to build and operate a cogeneration facility at Westvaco's Kraft Division Paper Mill in North Charleston, South Carolina. The facility began operations in March 1999. On September 10, 1998 the contractor in charge of construction filed suit in Circuit Court seeking approximately $52 million from Cogen, alleging that it incurred construction cost overruns relating to the facility and that the construction contract provides for recovery of these costs. In addition to Cogen, Westvaco, SCE&G and the Company were also named as defendants in the suit. The Company and the other defendants believe the suit is without merit and are mounting an appropriate defense. The Company does not believe that the resolution of this issue will have a material impact on its results of operations, cash flows or financial position. On December 2, 1999 an unsuccessful bidder for the purchase of the propane gas assets of SCANA filed suit against SCANA in Circuit Court seeking unspecified damages. The suit alleges the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. The Company is confident in its position and intends to vigorously defend the lawsuit. The Company does not believe that the resolution of this issue will have a material impact on its results of operations, cash flows or financial position. The Company is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company. 14. SEGMENT OF BUSINESS INFORMATION The Company's reportable segments, based on combined revenues from external and internal sources, are Electric Operations, Gas Distribution, Gas Transmission, Retail Gas Marketing and Energy Marketing. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company records intersegment sales and transfers of electricity and gas based on rates established by the appropriate regulatory authority. Non-regulated sales and transfers are recorded at current market prices. Electric Operations is comprised of the electric portion of SCE&G, GENCO and Fuel Company and is primarily engaged in the generation, transmission and distribution of electricity. SCE&G's electric service territory extends into 24 counties covering more than 15,000 square miles in the central, southern and southwestern portions of South Carolina. Sales of electricity to industrial, commercial and residential customers are regulated by the PSC. SCE&G is also regulated by FERC. GENCO owns and operates the Williams Station generating facility and sells all of its electric generation to SCE&G. GENCO is regulated by FERC. Fuel Company acquires, owns and provides financing for the fuel and emission allowances required for the operation of SCE&G and GENCO generation facilities. Gas Distribution, comprised of the local distribution operations of SCE&G and PSNC, is engaged in the purchase and sale, primarily at retail, of natural gas. SCE&G's operations extend to 31 counties in South Carolina covering approximately 21,000 square miles. PSNC was acquired by SCANA in 2000. PSNC's operations cover 25 counties in North Carolina and approximately 11,500 square miles. Gas Transmission is comprised of Pipeline Corporation, which is engaged in the purchase, transmission and sale of natural gas on a wholesale basis to distribution companies (including SCE&G), and directly to industrial customers in 40 counties throughout South Carolina. Pipeline Corporation also owns LNG liquefaction and storage facilities. Both of these segments are regulated by the state commission in their respective state of operations. Retail Gas Marketing markets natural gas in Georgia's deregulated natural gas market. Energy Marketing markets electricity, natural gas and other light hydrocarbons, primarily in the Southeast. The Company's regulated reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However, Electric Operations' product differs from the other segments, as does its generation process and method of distribution. The gas segments differ from each other primarily based on the class of customers each serves and the marketing strategies resulting from those differences. The marketing segments are non-regulated, but differ from each other primarily based on their respective markets. Disclosure of Reportable Segments Millions of dollars --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- --------------- Electric Gas Gas Retail Gas Energy All Adjustments/ Consolidated 2000 Operations Distribution Transmission Marketing Marketing Other Eliminations Total --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- --------------- External Customer Revenue $1,344 $745 $253 $548 $544 $41 $(42) $3,433 Intersegment Revenue 318 1 236 - - 9 (564) - Operating Income (Loss) 446 85 28 n/a n/a - (5) 554 Interest Expense 13 20 4 5 1 26 156 225 Depreciation & Amortization 155 53 7 1 - 5 (4) 217 Income Tax Expense (Benefit) 1 23 8 1 (1) (4) 113 141 Net Income (loss) 7 19 16 4 (4) (6) 214 250 Segment Assets 4,953 1,628 309 103 215 685 (473) 7,420 Expenditures for Assets 229 58 18 - - 8 48 361 Deferred Tax Assets 6 - 3 5 4 1 (19) - --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- --------------- Millions of dollars --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- --------------- Electric Gas Gas Retail Gas Energy All Adjustments/ Consolidated 1999 Operations Distribution Transmission Marketing Marketing Other Eliminations Total --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- --------------- External Customer Revenue $1,226 $234 $188 $207 $224 $73 $(74) $2,078 Intersegment Revenue 308 5 154 - - 11 (478) - Operating Income (Loss) 390 22 20 n/a n/a (79) 353 Interest Expense 12 n/a 4 4 1 23 98 142 Depreciation & Amortization 148 13 7 1 1 7 (8) 169 Income Tax Expense (Benefit) 1 n/a 9 (24) (2) 21 106 111 Net Income (loss) 6 n/a 14 (45) (4) 22 186 179 Segment Assets 4,751 399 253 (24) 168 932 (468) 6,011 Expenditures for Assets 201 19 8 2 1 6 24 261 Deferred Tax Assets 6 n/a 3 - 1 1 5 16 --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- --------------- Millions of dollars --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- --------------- Electric Gas Gas Retail Gas Energy All Adjustments/ Consolidated 1998 Operations Distribution Transmission Marketing Marketing Other Eliminations Total --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- --------------- External Customer Revenue $1,220 $225 $185 $3 $565 $68 $(160) $2,106 Intersegment Revenue 286 5 145 - - 8 (444) - Operating Income (Loss) 436 29 27 n/a n/a - (22) 470 Interest Expense 11 n/a 4 - - 19 89 123 Depreciation & Amortization 126 12 7 - - 7 (7) 145 Income Tax Expense (Benefit) - n/a 8 (4) (3) (2) 132 131 Net Income (loss) 6 n/a 16 (8) (7) (4) 220 223 Segment Assets 4,600 381 239 2 71 503 (515) 5,281 Expenditures for Assets 205 19 11 2 2 17 47 303 Deferred Tax Assets 5 n/a 3 - - 4 10 22 --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- --------------- Revenues and assets from segments below the quantitative thresholds are attributable to SCE&G's transit operations, which are regulated by the PSC, and to nine other wholly owned subsidiaries of the Company. These subsidiaries conduct non-regulated operations in energy-related and telecommunications industries. None of these subsidiaries met any of the quantitative thresholds for determining reportable segments in 2000, 1999 or 1998. Management uses operating income to measure segment profitability for regulated operations. For non-regulated operations, management uses net income for this purpose. Accordingly, SCE&G does not allocate interest charges or income tax expense (benefit) to the Electric Operations or Gas Distribution segments. Similarly, management evaluates utility plant for segments attributable to SCE&G and total assets for SCE&G as a whole, as well as for other operating segments. Therefore, SCE&G does not allocate accumulated depreciation, common and non-utility plant, or deferred tax assets to reportable segments. However, GENCO and PSNC do have interest charges, income taxes and deferred tax assets, which are included in Electric Operations and Gas Distribution, respectively. Interest income is not reported by segment and is not material. For 2000, adjustments to net income and income tax expense include the effect of the accounting change described in Note 2. The Consolidated Financial Statements report operating revenues which are comprised of the reportable segments. Revenues from non-reportable segments are included in Other Income. Therefore, the adjustments to total revenue remove revenues from non-reportable segments. Adjustments to Net Income consist of SCE&G's unallocated net income. Adjustments to assets consist of various reclassifications made for external reporting purposes. Segment assets include utility plant only (excluding accumulated depreciation) for Electric Operations, Gas Distribution and Transit Operations, and all assets for Gas Transmission and the remaining non-reportable segments. As a result, unallocated assets include accumulated depreciation, offset in part by common, non-utility and non-regulated plant for SCANA and SCE&G, and by non-fixed assets for Electric Operations, Gas Distribution and Transit Operations. Adjustments to Interest Expense, Income Tax Expense (Benefit) and Deferred Tax Assets include primarily the totals from SCANA or SCE&G that are not allocated to the segments. Interest Expense is also adjusted to eliminate inter-affiliate charges. Adjustments to depreciation and amortization consist of non-reportable segment expenses, which are not included in the depreciation and amortization reported on a consolidated basis. Deferred Tax Assets are also adjusted to remove the non-current portion of those assets. 15. SUBSEQUENT EVENTS On January 24, 2001 SCANA issued $202 million two-year floating rate notes maturing on January 24, 2003. The interest rate is reset quarterly based on three-month LIBOR plus 110 basis points. Also on January 24, 2001 SCE&G issued $150 million First Mortgage Bonds having an annual interest rate of 6.70 percent and maturing on February 1, 2011. On February 16, 2001 PSNC issued $150 million of medium-term notes having an annual interest rate of 6.625 percent and maturing on February 15, 2011. The proceeds from these borrowings were used to reduce short-term debt and for general corporate purposes. 16. QUARTERLY FINANCIAL DATA (UNAUDITED) (Millions of dollars, except per share amounts) --------------------------------------------------------------------------------------------------------------------------- First Second Third Fourth 2000 Quarter Quarter Quarter Quarter Annual ------------------------------------------------- ------------- ------------ ------------- -------------- ----------- Total operating revenues $821 $662 $816 $1,134 $3,433 Operating income 172(1) 99 146 137 554 Income before cumulative effect of accounting change 75 28 59 59 221 Cumulative effect of accounting change, net of taxes 29 - - - 29 Net income 104 28 59 59 250 Basic and diluted earnings per share before cumulative effect of accounting change .72 .27 .56 .57 2.12 Cumulative effect of accounting change, net of taxes .28 - - - .28 Basic and diluted earnings per share 1.00 .27 .56 .57 2.40 --------------------------------------------------------------------------------------------------------------------------- First Second Third Fourth 1999 Quarter Quarter Quarter Quarter Annual ------------------------------------------------- ------------- -------------- ----------- -------------- ----------- (Millions of Dollars, except per share amounts) Total operating revenues $546 $435 $558 $539 $2,078 Operating income 88 69 135 61 353 Net income 37 24 67 51 179 Basic and diluted earnings per share .36 .23 .65 .49 1.73 ------------------------------------------------- ------------- -------------- ----------- -------------- ----------- (1) Excludes $52 million of income taxes that were formerly reported in first quarter operating income. SOUTH CAROLINA ELECTRIC & GAS COMPANY Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.............................. 74 Item 7A. Quantitative Disclosures About Market Risk................. 84 Item 8. Financial Statements and Supplementary Data................ 84 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Statements included in this discussion and analysis (or elsewhere in this annual report) which are not statements of historical fact are intended to be, and are hereby identified as, "forward-looking statements" for purposes of the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following: (1) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) changes in the utility regulatory environment, (3) changes in the economy, especially in SCE&G's service territory, (4) the impact of competition from other energy suppliers, (5) growth opportunities, (6) the results of financing efforts, (7) changes in SCE&G's accounting policies, (8) weather conditions, especially in areas served by SCE&G, (9) inflation, (10) changes in environmental regulations and (11) the other risks and uncertainties described from time to time in SCE&G's periodic reports filed with the SEC. SCE&G disclaims any obligation to update any forward-looking statements. COMPETITION Regulated Electric and Gas Markets Efforts to restructure electric markets at the state level have slowed considerably. Dwindling operating reserves and rolling blackouts in parts of California in January and February 2001 have been widely reported nationwide. These shortages of electricity have been attributed to flawed state restructuring legislation, unplanned generating plant shutdowns and other economic factors. In response, many states that had passed or considered legislation to restructure the electric industry have stopped such efforts or are proceeding more slowly. In South Carolina, electric restructuring efforts have also stalled. The developments unfolding in California, and several unrelated, contentious issues before the General Assembly have combined to make consideration of electric restructuring legislation unlikely in 2001. Legislation or regulatory action at the Federal level, particularly as a part of a larger energy policy initiative, may be considered in 2001. SCE&G is not able to predict whether any restructuring legislation or regulatory action will be enacted and, if it is, the conditions it will impose on utilities. SCE&G has undertaken a variety of initiatives aimed at preparing for a restructured electric market. These initiatives include obtaining accelerated recovery of electric regulatory assets, establishing open access transmission tariffs and selling bulk power to wholesale customers at market-based rates. Marketing of services to commercial and industrial customers has also increased significantly, and SCE&G has obtained long term power supply contracts with a significant portion of its industrial customers. 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 evolving operating environment. Regulated public utilities are allowed to record as assets some costs that would be expensed by other enterprises. If deregulation or other changes in the regulatory environment occur, SCE&G may no longer be eligible to apply this accounting treatment and may be required to eliminate such regulatory assets from its balance sheet. Although the potential effects of deregulation cannot be determined at present, discontinuation of the accounting treatment could have a material adverse effect on SCE&G's results of operations in the period the write-off would be recorded. It is expected that cash flows and the financial position of SCE&G would not be materially affected by the discontinuation of the accounting treatment. SCE&G reported approximately $211 million and $65 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities of approximately $129 million and $52 million, respectively, on its balance sheet at December 31, 2000. SCE&G's generation assets are exposed to considerable financial risks in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, SCE&G could be required to write down its investment in these assets. SCE&G cannot predict whether any write-downs will be necessary and, if they are, the extent to which they would adversely affect SCE&G's results of operations in the period in which they would be recorded. As of December 31, 2000, SCE&G's net investment in fossil/hydro and nuclear generation assets was $1,154.9 million and $587.2 million, respectively. LIQUIDITY AND CAPITAL RESOURCES The cash requirements of SCE&G arise primarily from its operational needs, funding its construction program and payment of dividends to SCANA. The ability of SCE&G to replace existing plant investment, as well as to expand to meet future demand for electricity and gas, will depend upon its ability to attract the necessary financial capital on reasonable terms. SCE&G recovers the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and SCE&G continues its ongoing construction program, it may be necessary to seek increases in rates. As a result, SCE&G's future financial position and results of operations will be affected by its ability to obtain adequate and timely rate and other regulatory relief, if requested. The revised estimated primary cash requirements for 2001, excluding requirements for fuel liabilities and short-term borrowings and including notes payable to affiliated companies, and the actual primary cash requirements for 2000 are as follows: Millions of dollars 2001 2000 -------------------------------------------------------------- -------------- Property additions and construction expenditures, net of allowance for funds used during construction $396 $248 Nuclear fuel expenditures 26 29 Investments - 1 Maturing obligations, redemptions and sinking and purchase fund requirements 5 104 ------------------------------------------------------------- -------------- Total $427 $382 ============================================================== ============== Approximately 63 percent of total cash requirements (after payment of dividends) was provided from internal sources in 2000 as compared to 69 percent in 1999. SCE&G anticipates that its 2001 cash requirements of $427 million will be met through internally generated funds (approximately 64 percent, after payment of dividends) and the incurrence of additional short-term and long-term indebtedness. SCE&G expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the next 12 months and for the foreseeable future. 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 18 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, 2000 the Bond Ratio was 6.43. The Old Mortgage allows the issuance of additional Class A Bonds to an additional principal amount equal to (i) 70 percent of unfunded net property additions (which unfunded net property additions totaled approximately $1,452 million at December 31, 2000), (ii) retirements of Class A Bonds (which retirement credits totaled $68.4 million at December 31, 2000), and (iii) cash on deposit with the Trustee. SCE&G is subject to a bond indenture dated April 1, 1993 (New Mortgage) covering substantially all of its electric properties under which its future mortgage-backed debt (New Bonds) will be issued. New Bonds are issued under the New Mortgage on the basis of a like principal amount of Class A Bonds issued under the Old Mortgage which have been deposited with the Trustee of the New Mortgage (of which $665 million were available for such purpose as of December 31, 2000). 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, 2000 the New Bond Ratio was 6.34. The following additional financing transactions have occurred since January 1, 2000: o On June 14, 2000 SCE&G issued $150 million of First Mortgage Bonds having an annual interest rate of 7.50 percent and maturing on June 15, 2005. The proceeds from the sale of these bonds were used to pay the maturity of SCE&G's $100 million First Mortgage Bonds due June 15, 2000, to reduce short-term debt and for general corporate purposes. o On January 24, 2001 SCE&G issued $150 million First Mortgage Bonds having an annual interest rate of 6.70 percent and maturing on February 1, 2011. The proceeds from the sale of these bonds were used to reduce short-term debt and for general corporate purposes. 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 ten percent of the aggregate principal amount of all of SCE&G's secured indebtedness and capital and surplus; however, no such consent is 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 must obtain FERC authority to issue short-term debt. The FERC has authorized SCE&G to issue up to $250 million of unsecured promissory notes or commercial paper with maturity dates of 12 months or less, but not later than December 31, 2002. At December 31, 2000 SCE&G had $250 million of unused authorized lines of credit which consists of a credit agreement for a maximum of $250 million to support the issuance of commercial paper. SCE&G's commercial paper outstanding at December 31, 2000 and 1999 was $117.5 million and $143.1 million, respectively. In addition, Fuel Company has a credit agreement for a maximum of $125 million with the full amount available at December 31, 2000. The credit agreement supports the issuance of short-term commercial paper for the financing of nuclear and fossil fuels and sulfur dioxide emission allowances. Fuel Company commercial paper outstanding at December 31, 2000 was $70.2 million. This commercial paper and amounts outstanding under the revolving credit agreement, if any, are guaranteed by SCE&G. 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, 2000 the Preferred Stock Ratio was 2.09. On September 21, 1999 SCE&G announced a $256 million gas turbine generator project in Aiken County, South Carolina. Two combined-cycle turbines will burn natural gas to produce 300 megawatts of new electric generation and use exhaust heat to replace coal-fired steam that powers two existing 75 megawatt turbines at the Urquhart Generating Station. The turbine project is scheduled to be completed by June 2002. On October 15, 1999 FERC notified SCE&G of its agreement with SCE&G's plan to reinforce Lake Murray Dam in order to maintain the lake in case of an extreme earthquake. SCE&G and FERC are discussing possible reinforcement alternatives for the dam over the past several years as part of SCE&G's ongoing hydroelectric operating license with FERC. Until discussions are concluded, it is not possible to finalize the cost of the project; however, it is possible that the cost could range up to $250 million. Although any costs incurred by SCE&G are expected to be recoverable through electric rates, SCE&G also is exploring alternative sources of funding. The project is expected to be completed in 2004. On October 7, 2000 Summer Station was removed from service for a planned maintenance and refueling outage scheduled to last 38 1/2 days. During initial inspection activities, plant personnel discovered a small leak coming from a hole in a weld in a primary coolant system pipe. SCE&G performed extensive ultrasonic testing of similar welds in the cooling system, which confirmed that the problem was limited to this single weld. A root cause analysis determined that the cause of the crack was primary water stress corrosion cracking. The repair involved cutting out a twelve-inch long spool of the pipe, which included the entire weld, and installing a new spool piece. Repairs have been completed and the integrity of the new welds have been verified through extensive testing. The plant was returned to service in March 2001. The NRC was closely involved throughout this process and approved SCE&G's actions to repair the crack, as well as the restart schedule. SCE&G will continue to monitor primary coolant system pipes during the next outage, scheduled for Spring of 2002. SCE&G recorded a pretax charge of approximately $6 million in the fourth quarter of 2000 to expense repair costs to date. Additional costs that may be recorded in the first quarter of 2001 are not expected to be material. The cost of replacement power is expected to be recovered through SCE&G's electric fuel adjustment clause. In January 2001 SCE&G's 385 megawatt coal-fired Cope Generating Station was taken out of service due to an electrical ground in the generator. The unit is expected to be returned to service in Spring 2001. The cost of replacement power is expected to be recovered through SCE&G's fuel adjustment clause. SCANA and Westvaco each own a 50 percent interest in Cogen South LLC (Cogen). Cogen was formed to build and operate a cogeneration facility at Westvaco's Kraft Division Paper Mill in North Charleston, South Carolina. The facility began operations in March 1999. On September 10, 1998 the contractor in charge of construction filed suit in Circuit Court seeking approximately $52 million from Cogen, alleging that it incurred construction cost overruns relating to the facility, and that the construction contract provides for recovery of these costs. In addition to Cogen, Westvaco, SCE&G and SCANA were also named as defendants in the suit. SCE&G and the other defendants believe the suit is without merit and are mounting an appropriate defense. SCE&G does not believe that the resolution of this issue will have a material impact on its results of operations, cash flows or financial position. Environmental Matters The CAA required electric utilities to reduce emissions of sulfur dioxide and nitrogen oxide substantially by the year 2000. These requirements were phased in over two periods. The first phase had a compliance date of January 1, 1995 and the second, January 1, 2000. SCE&G's facilities did not require modifications to meet the requirements of Phase I. SCE&G is meeting the Phase II requirements through the burning of natural gas and/or lower sulfur coal in its generating units and the purchase and use of sulfur dioxide emission allowances. Low nitrogen oxide burners have been installed to reduce nitrogen oxide emissions to the levels required by Phase II. The EPA has indicated that it will propose regulations for stricter limits on mercury and other toxic pollutants generated by coal-fired plants by December 2003 and will begin developing these regulations shortly. SCE&G filed compliance plans with DHEC related to Phase II sulfur dioxide requirements in 1995 and Phase II oxides of nitrogen oxide (NOx) requirements in 2000, 1999, 1998 and 1997. SCE&G currently estimates that air emissions control equipment will require capital expenditures of $82 million over the 2001-2005 period to retrofit existing facilities, with increased operation and maintenance costs of approximately $2 million per year. To meet compliance requirements for the years 2006 through 2010, SCE&G anticipates additional capital expenditures of approximately $5 million. In October 1998, the EPA issued a final rule requiring 22 states, including South Carolina, to modify their state implementation plans (SIP) to address the issue of NOx pollution. On May 25, 1999, a federal appeals court delayed indefinitely the implementation of the rule. On March 3, 2000, the court affirmed the EPA's NOx rule for the affected states. South Carolina was subsequently ordered to amend its SIP to achieve significant NOx reductions. South Carolina failed to submit a revised SIP as required under the CAA, and EPA has issued official notice to South Carolina (and a number of other states) to comply. While not final, South Carolina has proposed NOx reductions that would require SCE&G to install pollution control equipment. Because DHEC had not amended its SIP as of December 31, 2000 to set out or allocate any NOx reductions, it is not possible to estimate what, if any, capital expenditures will be required to comply with any potential mandated reductions. The EPA has undertaken an aggressive enforcement initiative against the industry and the Department of Justice (DOJ) has brought suit against a number of utilities in federal court alleging violations of the CAA. Prior to the suits, those utilities had received requests for information under Section 114 of the CAA, and were issued Notices of Violation prior to the suits. The basis for these suits is the claim by the EPA that maintenance activities undertaken by the utilities over the past 20 or more years constitute "major modifications" which would have required the installation of costly Best Available Control Technology (BACT). SCE&G has received and responded to Section 114 requests for information related to its Canadys and Wateree Stations. Similar requests have been sent to a number of other utilities nation wide. The regulations under the CAA provide certain exemptions to the definition of "major modifications," particularly an exemption for routine repair, replacement or maintenance. SCE&G has analyzed each of the activities covered by the EPA's requests and believes each activity represents prudent practice regularly performed throughout the utility industry as necessary to maintain the operational efficiency and safety of equipment. As such, SCE&G believes that each of these activities is covered by the exemption for routine repair, replacement and maintenance and that the EPA is changing, or attempting to change through enforcement actions, the intent and meaning of its regulations. SCE&G also believes that, even if some of the activities in question were found not to qualify for the routine exemption, there were no increases either in annual emissions or in the maximum hourly emissions achievable at any of the units caused by any of the activities. The regulations provide an exemption for increased hours of operation or production rate and for increases in emissions resulting from demand growth. It is possible that the EPA will eventually commence enforcement actions against SCE&G relative to those plants. The EPA has the authority to seek penalties for the alleged violations in question at the rate of up to $27,500 per day for each violation. The EPA also would also seek installation of BACT (or equivalent) at the three plants as well. SCE&G believes that the EPA's and DOJ's claims are without merit, and that any enforcement action, up to and including a lawsuit resulting from this issue, will not have a material adverse effect on SCE&G's financial position or results of operations. The Federal Clean Water Act, as amended, provides for the imposition of effluent limitations that require various levels of treatment for each waste water 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 generating units. Concurrent with renewal of these permits, the permitting agency has implemented a more rigorous program in monitoring and controlling thermal discharges and strategies for toxicity reduction in wastewater streams. SCE&G has been developing compliance plans for these initiatives. Amendments to the Clean Water Act proposed in Congress include several provisions which, if passed, could prove costly to SCE&G. These include, but are not limited to, limitations to mixing zones and the implementation of technology-based standards. In December 2000, SCE&G entered into a Consent Order with DHEC related to a malfunction of the waste water treatment facility at Hagood Station. The order requires SCE&G to correct the violation. SCE&G maintains an environmental assessment program to identify and assess current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate primarily to regulated operations. Such amounts are deferred and amortized with recovery provided through rates. SCE&G has also recovered portions of its environmental liabilities through settlements with various insurance carriers, including all amounts previously deferred for its electric operations. SCE&G expects to recover all deferred amounts related to its gas operations by December 2005. Deferred amounts, net of amounts recovered through rates and insurance settlements, totaled $20.2 million and $23.7 million at December 31, 2000 and 1999, respectively. The deferral includes the estimated costs associated with the following matters. o 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 encompasses approximately 30 acres and includes properties which were locations for industrial operations, including a wood preserving (creosote) plant, one of SCE&G's decommissioned MGPs, properties owned by the National Park Service and the City of Charleston, and private properties. The site has not been placed on the National Priorities List, but may be added in the future. The PRPs negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study and a corresponding Scope of Work. Field work began in November 1993, and the EPA approved a Remedial Investigation Report in February 1997 and a Feasibility Study Report in June 1998. In July 1998 the EPA approved SCE&G's Removal Action Work Plan for soil excavation. SCE&G completed Phase One of the Removal Action Work Plan in 1998 at a cost of approximately $1.5 million. Phase Two, which cost approximately $3.5 million, included excavation and installation of several permanent barriers to mitigate coal tar seepage. On September 30, 1998 a Record of Decision was issued which sets forth the EPA's view of the extent of each PRP's responsibility for site contamination and the level to which the site must be remediated. SCE&G estimates that the Record of Decision will result in costs of approximately $13.3 million, of which approximately $2 million remains. On January 13, 1999 the EPA issued a Unilateral Administrative Order for Remedial Design and Remedial Action directing SCE&G to design and carry out a plan of remediation for the Calhoun Park site. SCE&G submitted a Comprehensive Remedial Design Work Plan (RDWP) on December 17, 1999, and proceeded with implementation pending agency approval. The RDWP was approved by the EPA in July 2000, and its implementation continues. In October 1996 the City of Charleston and SCE&G settled all environmental claims the City may have had against SCE&G involving the Calhoun Park area for a payment of $26 million over four years (1996-1999) by SCE&G to the City. SCE&G is recovering the amount of the settlement, which does not encompass site assessment and cleanup costs, through rates in the same manner as other amounts accrued for site assessments and cleanup as discussed above. As part of the environmental settlement, SCE&G constructed an 1,100 space parking garage on the Calhoun Park site (construction was completed in April 2000) and transferred the facility to the City in exchange for a $16.5 million, 18-year municipal bond collaterized by revenues from, and a mortgage on, the parking garage. o SCE&G owns three other decommissioned MGP sites which contain residues of by-product chemicals. For the site located in Sumter, South Carolina, effective September 15, 1998, SCE&G entered into a Remedial Action Plan Contract with DHEC pursuant to which it agreed to undertake a full site investigation and remediation under the oversight of DHEC. Site investigation and characterization are proceeding according to schedule. Upon selection and successful implementation of a site remedy, DHEC will give SCE&G a Certificate of Completion, and a covenant not to sue. For the site located in Florence, South Carolina, SCE&G entered into a similar Remedial Action Plan Contract with DHEC effective September 5, 2000. SCE&G is continuing to investigate the remaining site in Columbia, and is monitoring the nature and extent of residual contamination. Regulatory Matters On July 20, 2000 the PSC issued an order approving SCE&G's request for an out-of-period adjustment to increase the cost of gas component of its rates for natural gas service from 54.334 cents per therm to 68.835 cents per therm, effective with the first billing cycle in August 2000. As part of its regularly scheduled annual review of gas costs, the PSC issued an order on November 9, 2000 which further increased the cost of gas component to 78.151 cents per therm, effective with the first billing cycle in November 2000. On December 21, 2000 the PSC issued an order approving SCE&G's request for another out-of-period adjustment to increase the cost of gas component to 99.340 cents per therm, effective with the first billing cycle in January 2001. In March 2001 the PSC approved SCE&G's request to decrease the cost of gas component to 79.340 cents per therm, effective with the first billing cycle in March 2001. On July 5, 2000 the PSC approved SCE&G's request to implement lower depreciation rates for its gas operations. The new rates were effective retroactively to January 1, 2000 and will result in a reduction in annual depreciation expense of approximately $2.9 million. On September 14, 1999 the PSC approved an accelerated capital recovery plan for SCE&G's Cope Generating Station. The plan was implemented beginning January 1, 2000 for a three-year period. The PSC approved an accelerated capital recovery methodology wherein SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates. The amount of the accelerated depreciation will be determined by SCE&G based on the level of revenues and operating expenses, not to exceed $36 million annually without the approval of the PSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year. As of December 31, 2000 no accelerated depreciation has been recorded. The accelerated capital recovery plan will be accomplished through existing customer rates. On December 11, 1998 the PSC issued an order requiring SCE&G to reduce retail electric rates on a prospective basis. The PSC acted in response to SCE&G reporting that it earned a 13.04 percent return on common equity for its retail electric operations for the 12 months ended September 30, 1998. This return on common equity exceeded SCE&G's authorized return of 12.0 percent by 1.04 percent, or $22.7 million, primarily as a result of record heat experienced during the summer. The order required prospective rate reductions on a per kilowatt-hour basis, based on actual retail sales for the 12 months ended September 30, 1998. On January 12, 1999 the PSC denied SCE&G's motion for reconsideration, ruled that no further rate action was required, and reaffirmed SCE&G's authorized return on equity of 12.0 percent. The rate reductions were placed into effect with the first billing cycle of January 1999. On January 9, 1996 the PSC issued an order granting SCE&G an increase in retail electric rates which were fully implemented by January 1997. The PSC authorized a return on common equity of 12.0 percent. The PSC also approved establishment of a Storm Damage Reserve Account capped at $50 million to be collected through rates over a ten-year period. Additionally, the PSC approved accelerated recovery of a significant portion of SCE&G's electric regulatory assets (excluding deferred income tax assets) and the remaining transition obligation for postretirement benefits other than pensions, changing the amortization periods to allow recovery by the end of the year 2000. SCE&G's request to shift, for rate-making purposes, approximately $257 million of depreciation reserves from transmission and distribution assets to nuclear production assets was also approved. The Consumer Advocate and two other intervenors appealed certain issues in the order initially to the Circuit Court, which affirmed the PSC's decisions, and subsequently, to the Supreme Court. In March 1998, SCE&G, the PSC, the Consumer Advocate and one of the other intervenors reached an agreement that provided for the reversal of the shift in depreciation reserves and the dismissal of the appeal of all other issues. The PSC also authorized SCE&G to adjust depreciation rates that had been approved in the 1996 rate order for its electric transmission, distribution and nuclear production properties to eliminate the effect of the depreciation reserve shift and to retroactively apply such depreciation rates to February 1996. As a result, a one-time reduction in depreciation expense of $9.8 million was recorded in March 1998. The agreement does not affect retail electric rates. The FERC had previously rejected the transfer of depreciation reserves for rates subject to its jurisdiction. In September 1998 the Supreme Court affirmed the Circuit Court's rulings on the issues contested by the remaining intervenor. In 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 MGPs. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for SCE&G's gas operations that had previously been deferred. In November 2000, as a result of the annual review, the PSC approved SCE&G's request to maintain the billing surcharge at $.011 per therm to provide for the recovery of the remaining balance of $20.1 million. In September 1992 the PSC issued an order granting SCE&G's request for a $.25 increase in transit fares from $.50 to $.75 in Columbia, 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 in October 1992. SCE&G appealed the PSC's order to the Circuit Court, which in May 1995 ordered the case back to the PSC for reconsideration of several issues including the low income rider program, routing changes, and the $.75 fare. The Supreme Court declined to review an appeal of the Circuit Court decision and dismissed the case. The PSC and other intervenors filed another Petition for Reconsideration, which the Supreme Court denied. The PSC and other intervenors filed another appeal to the Circuit Court which the Circuit Court denied in an order dated May 9, 1996. In this order, the Circuit Court upheld its previous orders and remanded them to the PSC. During August 1996 the PSC heard oral arguments on the orders on remand from the Circuit Court. On September 30, 1996 the PSC issued an order affirming its previous orders and denied SCE&G's request for reconsideration. In response to an appeal of the PSC's order by SCE&G, the Circuit Court issued an order on May 25, 2000, which remanded the matter to the PSC for review of SCE&G's original application and request to terminate the low income rider fare. On September 27, 2000 the PSC issued an order granting the relief requested by SCE&G. On September 29, 2000 the Consumer Advocate filed a motion with the PSC for a stay of this order to which SCE&G filed a response. On October 3, 2000 the PSC accepted the Consumer Advocate's motion and issued a stay of its order. The Consumer Advocate and other intervenors have petitioned the Circuit Court for judicial review of the PSC's order granting relief. Action by the Circuit Court is pending. Other In June 1998 the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) 133, "Accounting for Derivative Instruments and Hedging Activities." In June 2000 the FASB issued SFAS 138, which amends certain provisions of SFAS 133 to expand the normal purchase and sale exemption for supply contracts and to redefine interest rate risk to reduce sources of ineffectiveness, among other things. SCE&G's adoption of SFAS 133, as amended, on January 1, 2001 did not have a material impact on SCE&G's results of operations, cash flows or financial position. In December 1999, Staff Accounting Bulletin No. 101, "Revenue Recognition in Financial Statements" was issued by the SEC, and provides the SEC staff's views in applying generally accepted accounting principles to selected revenue recognition issues. SCE&G's adoption of the bulletin in the fourth quarter of 2000 had no impact on its results of operations, cash flows or financial position. RESULTS OF OPERATIONS Net Income Net income and the percent change from the previous year for the years 2000, 1999 and 1998 were as follows: Millions of dollars 2000 1999 1998 -------------------------------------------------------------------------------- Net income derived from: Continuing operations $231.3 $189.2 $227.2 Cumulative effect of accounting change $22.3 - - ================================================================================ Net income $253.6 $189.2 $227.2 ================================================================================ Percent increase (decrease) in net income 34.04% (16.75%) 16.72% -------------------------------------------------------------------------------- o 2000 vs 1999 Net income increased primarily as a result of more favorable weather, customer growth and pension income. These were partially offset by higher purchased power costs and a charge for repairs at Summer Station. o 1999 vs 1998 Net income decreased primarily due to a rate reduction, milder weather, and higher fuel costs. In addition, completion of a new customer billing system and cogeneration facility, among other factors, resulted in increased operating and depreciation expenses. These factors were partially offset by customer growth. Also affecting the decrease in net income was the depreciation reduction recorded in 1998 (as discussed below). Pension income recorded by SCE&G reduced operations expense by $20.9 million, $16.3 million and $16.6 million for the years ended December 31, 2000, 1999 and 1998, respectively. In addition, pension income increased other income by $12.9 million, $10.5 million and $9.0 million for the years ended December 31, 2000, 1999 and 1998, respectively. The reductions to operations expense for 1999 and 1998 were substantially offset by accelerated amortization of a significant portion of the transition obligation for postretirement benefits other than pensions and certain regulatory assets as approved by the PSC. Effective July 1, 2000 SCE&G's pension plan was amended to provide a cash balance formula. The effect of this plan amendment was to reduce net periodic benefit income for the year ended December 31, 2000 by approximately $3.4 million. SCE&G'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 1.7 percent of income before income taxes in 2000, 2.0 percent in 1999 and 3.8 percent in 1998. Electric Operations Electric Operations is comprised of the electric portion of SCE&G and Fuel Company. Electric operations sales margins, excluding the cumulative effect of accounting change, for 2000, 1999 and 1998 were as follows: Millions of dollars 2000 1999 1998 ------------------------------------------------------------------------------ Electric revenue $1,343.8 $1,226.0 $1,219.8 Less: Fuel used in electric generation (231.6) (214.4) (212.3) Purchased power (182.7) (141.5) (116.4) ------------------------------------------------------------------------------ Margin $929.5 $870.1 $891.1 ============================================================================== o 2000 vs 1999 Sales margin increased primarily due to more favorable weather and customer growth, which was partially offset by higher purchased power costs. o 1999 vs 1998 Sales margin decreased primarily due to the impact of a rate reduction, milder weather and higher purchased power costs, which were partially offset by customer growth. Increases (decreases) from the prior year in megawatt-hour (MWH) sales volume by classes, excluding volumes attributable to the cumulative effect of accounting change, were as follows: Classification 2000 % Change 1999 % Change ------------------------------------------ ------------ ------------- ------------- Residential 396,179 6.3% (55,208) (0.9%) Commercial 353,621 5.9% 52,440 0.9% Industrial 524,969 8.5% 316,087 5.4% Sales for Resale (excluding interchange) 33,505 2.8% 63,306 5.6% Other 34,676 6.7% (17,652) (3.3%) ------------------------------------------ ------------- Total territorial 1,342,950 6.7% 358,973 - Negotiated Market Sales Tariff 264,257 15.7% 183,442 12.3% ------------------------------------------ ------------- Total 1,607,207 7.4% 542,415 2.6% ========================================== ============ ============= ============= o 2000 vs 1999 Sales volume increased primarily due to more favorable weather and customer growth. o 1999 vs 1998 Sales volume decreased for residential primarily due to milder weather, which was partially offset by customer growth. Volumes for the remaining classes increased primarily due to customer growth. Gas Distribution Gas Distribution is comprised of the local distribution operations of SCE&G. Gas distribution sales margins, excluding the cumulative effect of accounting change, for 2000, 1999 and 1998 were as follows: Millions of dollars 2000 1999 1998 --------------------------------------------- -------------- ------------ Gas operating revenues $325.1 $239.0 $230.4 Less: Gas purchased for resale 233.8 152.6 142.4 --------------------------------------------- -------------- ------------ Margin $91.3 $86.4 $88.0 ============================================= ============== ============ o 2000 vs 1999 Sales margin increased primarily as a result of more favorable weather, which was partially offset by higher gas costs. o 1999 vs 1998 Sales margin decreased primarily as a result of higher gas costs. Increases (decreases) from the prior year in dekatherm (DT) sales volume by classes, including transportation gas and excluding volumes attributable to the cumulative effect of accounting change, were as follows: Classification 2000 % Change 1999 % Change ------------------------------- ------------- ------------ ------------ Residential 411,985 3.5% (94,027) (0.8%) Commercial 377,347 3.2% 404,654 3.6% Industrial (828,737) (4.6%) 644,485 3.7% Transportation gas 110,220 5.6% (28,732) (1.4%) ------- -------- Total 70,815 0.2% 926,380 2.2% =============================== ============= ============ ============ o 2000 vs 1999Sales volume increased approximately 2.0 million DTs due to colder weather and customer growth, which was partially offset by curtailments and use of alternate fuels by industrial customers. o 1999 vs 1998 Sales volume increased primarily as a result of customer growth. Residential volume decreased primarily due to milder weather. Other Operating Expenses Increases (decreases) in other operating expenses were as follows: Millions of dollars 2000 1999 -------------------------------------------------- --------------------- Other operation and maintenance $(8.2) $7.0 Depreciation and amortization 4.8 22.3 Other taxes 3.5 1.8 -------------------------------------------------- --------------- Total $0.1 $31.1 ================================================== =============== o 2000 vs 1999Other operation and maintenance decreased due to pension income (see Net Income), which was partially offset by increased maintenance costs for electric generating and distribution facilities. Depreciation and amortization increased primarily due to normal increases in utility plant. Other taxes increased primarily due to increased property taxes. o 1999 vs 1998 Other operation and maintenance increased primarily due to a shift in labor from capital to expense related to the completion of a new customer billing system, a cogeneration facility becoming operational, and other operating costs. These costs were partially offset by pension income, which in 1998 had been offset by the accelerated amortization of SCE&G's transition obligation expense for post-retirement benefits and other regulatory assets. Depreciation and amortization increased primarily due to the impact of the non-recurring adjustment to depreciation expense discussed under Net Income, increased amortization due to completion of a new customer billing system, and normal increases in utility plant. Other taxes increased primarily due to increased property taxes. Interest Expense Increases (decreases) in interest expense, excluding the debt component of AFC, were as follows: Millions of dollars 2000 1999 ------------------------------------------------ --------------------- Interest on long-term debt, net $4.0 $1.9 Other interest expense (0.5) 2.4 ------------------------------------------------- --------------------- Total $3.5 $4.3 ================================================= ===================== Interest expense in 2000 increased as a result of increased borrowings and increased weighted average interest rates on short-term and long-term borrowings. Interest expense in 1999 increased as a result of increased borrowings. Income Taxes Income taxes increased approximately $23.4 million for the year 2000 compared to 1999 and decreased approximately $22.4 million for the year ended 1999 compared to 1998. Changes in income taxes are primarily due to changes in operating income. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK All financial instruments held by SCE&G described below are held for purposes other than trading. Interest rate risk - The table below provides information about SCE&G's financial instruments that are sensitive to changes in interest rates. For debt obligations the table presents principal cash flows and related weighted average interest rates by expected maturity dates. December 31, 2000 Expected Maturity Date Millions of dollars Liabilities 2001 2002 2003 2004 2005 Thereafter Total Fair Value ----------- ---- ---- ---- ---- ---- ---------- ----- ---------- --------------------------- ------------ ----------- ----------- ----------- ----------- ------------- ------------- ------------ Long-Term Debt: Fixed Rate ($) 27.6 27.6 129.5 123.9 173.9 932.5 1,415.0 1,331.6 ------------------- Average Interest Rate 6.72% 6.72% 6.37% 7.52% 7.40% 7.55% 7.39% December 31, 1999 Expected Maturity Date Millions of dollars Liabilities 2000 2001 2002 2003 2004 Thereafter Total Fair Value --------------------------- ------------ ----------- ----------- ----------- ----------- ------------- ------------- ------------ Long-Term Debt: Fixed Rate ($) 127.5 27.6 27.6 129.4 123.9 933.0 1,369.0 1,232.7 Average Interest Rate 6.16% 6.73% 6.73% 6.37% 7.52% 7.72% 7.39% While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Page Independent Auditors' Report............................................... 85 Consolidated Financial Statements: Consolidated Balance Sheets as of December 31, 2000 and 1999........... 86 Consolidated Statements of Income and Retained Earnings for years ended December 31, 2000, 1999 and 1998................... 88 Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998.................................... 89 Consolidated Statements of Capitalization as of December 31, 2000 and 1999................................................. 90 Notes to Consolidated Financial Statements............................. 92 INDEPENDENT AUDITORS' REPORT South Carolina Electric & Gas Company: We have audited the accompanying Consolidated Balance Sheets and Statements of Capitalization of South Carolina Electric & Gas Company (Company) as of December 31, 2000 and 1999 and the related Consolidated Statements of Income and Retained Earnings and Cash Flows for each of the three years in the period ended December 31, 2000. Our audits also included the financial statement schedule listed in Part IV at Item 14. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, 2000 and 1999 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein. As discussed in Note 2 to the consolidated financial statements, effective January 1, 2000, the Company changed its method of accounting for operating revenues. s/Deloitte & Touche LLP DELOITTE & TOUCHE LLP Columbia, South Carolina February 7, 2001 SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED BALANCE SHEETS ----------------------------------------------------------------------------- ----------------- ------------------- December 31, (Millions of dollars) 2000 1999 ----------------------------------------------------------------------------- ----------------- ------------------- Assets Utility Plant (Notes 1 & 5): Electric $4,453 $4,337 Gas 409 392 Other 186 191 ----------------------------------------------------------------------------- ----------------- ------------------- Total 5,048 4,920 Less accumulated depreciation and amortization 1,720 1,611 ----------------------------------------------------------------------------- ----------------- ------------------- Total 3,328 3,309 Construction work in progress 230 149 Nuclear fuel, net of accumulated amortization 57 43 ----------------------------------------------------------------------------- ----------------- ------------------- Utility Plant, Net 3,615 3,501 ----------------------------------------------------------------------------- ----------------- ------------------- Nonutility Property and Investments, net of accumulated depreciation 21 19 ----------------------------------------------------------------------------- ----------------- ------------------- Current Assets: Cash and temporary cash investments (Notes 1 &11) 60 78 Receivables 287 195 Inventories (At average cost) (Note 6): Fuel 21 30 Materials and supplies 46 48 Emission allowances 20 17 Prepayments 5 8 Deferred income taxes, net (Notes 1 & 10) - 16 ----------------------------------------------------------------------------- ----------------- ------------------- Total Current Assets 439 392 ----------------------------------------------------------------------------- ----------------- ------------------- Deferred Debits: Emission allowances 3 14 Environmental 20 24 Nuclear plant decommissioning fund (Note 1) 72 64 Pension asset, net (Note 4) 196 144 Other regulatory assets (Note 1) 191 164 Other 107 82 ----------------------------------------------------------------------------- ----------------- ------------------- Total Deferred Debits 589 492 ----------------------------------------------------------------------------- ----------------- ------------------- Total $4,664 $4,404 ============================================================================= ================= =================== SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED BALANCE SHEETS ----------------------------------------------------------------------- -------------------- -------------------- December 31, (Millions of dollars) 2000 1999 ----------------------------------------------------------------------- -------------------- -------------------- Capitalization and Liabilities Stockholders' Investment: Common equity (Note 8) $1,657 $1,558 Preferred stock (Not subject to purchase or sinking funds) (Note 9) 106 106 ----------------------------------------------------------------------- -------------------- -------------------- Total Stockholders' Investment 1,763 1,664 Preferred Stock, net (Subject to purchase or sinking funds) 10 11 Company-Obligated Mandatorily Redeemable Preferred Securities of the Company's Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount of the 7.55% Junior Subordinated Debentures of SCE&G, due 2027 50 50 Long-Term Debt, net (Notes 5 & 11) 1,267 1,121 ----------------------------------------------------------------------- -------------------- -------------------- Total Capitalization 3,090 2,846 ----------------------------------------------------------------------- -------------------- -------------------- Current Liabilities: Short-term borrowings (Notes 6, 7 & 11) 188 213 Current portion of long-term debt (Note 5) 28 128 Accounts payable 103 78 Accounts payable - affiliated companies (Note 1) 58 33 Customer deposits 17 17 Taxes accrued 51 60 Interest accrued 22 22 Dividends declared 44 28 Deferred income taxes, net (Notes 1 & 10) 20 - Other 10 10 ----------------------------------------------------------------------- -------------------- -------------------- Total Current Liabilities 541 589 ----------------------------------------------------------------------- -------------------- -------------------- Deferred Credits: Deferred income taxes, net (Notes 1 & 10) 584 560 Deferred investment tax credits (Notes 1 & 10) 109 108 Reserve for nuclear plant decommissioning (Note 1) 72 64 Postretirement benefits (Note 4) 113 98 Other regulatory liabilities 65 59 Other (Note 1) 90 80 ----------------------------------------------------------------------- -------------------- -------------------- Total Deferred Credits 1,033 969 ----------------------------------------------------------------------- -------------------- -------------------- Commitments and Contingencies (Note 12) - - ----------------------------------------------------------------------- -------------------- -------------------- Total $4,664 $4,404 ======================================================================= ==================== ==================== See Notes to Consolidated Financial Statements. SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS ----------------------------------------------------------------------- ------------------ ---------------- --------------- -- For the Years Ended December 31, 2000 1999 1998 ----------------------------------------------------------------------- ------------------ ---------------- --------------- -- (Millions of Dollars, except per share amounts) Operating Revenues (Notes 1, 2 & 3): Electric $1,344 $1,226 $1,220 Gas 325 239 230 ----------------------------------------------------------------------- ------------------ ---------------- --------------- -- Total Operating Revenues 1,669 1,465 1,450 ----------------------------------------------------------------------- ------------------ ---------------- --------------- -- Operating Expenses: Fuel used in electric generation 232 214 212 Purchased power (including affiliated purchases of $100, $106 and $185) 183 142 116 Gas purchased for resale 234 153 142 Other operation and maintenance (Note 1) 308 316 309 Depreciation and amortization (Note 1) 158 153 131 Other taxes 97 94 92 ----------------------------------------------------------------------- ------------------ ---------------- --------------- -- Total Operating Expenses 1,212 1,072 1,002 ----------------------------------------------------------------------- ------------------ ---------------- --------------- -- Operating Income 457 393 448 ----------------------------------------------------------------------- ------------------ ---------------- --------------- -- Other Income: Other Income, including allowance for equity funds used during construction (Note 1) 14 9 9 Gain on sale of assets 2 3 - ----------------------------------------------------------------------- ------------------ ---------------- --------------- -- Total Other Income 16 12 9 ----------------------------------------------------------------------- ------------------ ---------------- --------------- -- Income Before Interest Charges, Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change 473 405 457 ----------------------------------------------------------------------- ------------------ ---------------- --------------- -- Interest Charges: Interest expense on long-term debt, net 101 97 95 Other interest expense, net of allowance for borrowed funds used during construction (Note 1) 4 5 (1) ----------------------------------------------------------------------- ------------------ ---------------- --------------- -- Total Interest Charges, Net 105 102 94 ----------------------------------------------------------------------- ------------------ ---------------- --------------- -- Income Before Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change 368 303 363 Income Taxes (Note 10) 133 110 132 ----------------------------------------------------------------------- ------------------ ---------------- --------------- -- Income Before Preferred Stock Dividends and Cumulative Effect of Accounting Change 235 193 231 Preferred Dividend Requirement of Company - Obligated Mandatorily Redeemable Preferred Securities 4 4 4 ----------------------------------------------------------------------- ------------------ ---------------- --------------- -- Income Before Cumulative Effect of Accounting Change 231 189 227 Cumulative Effect of Accounting Change, net of taxes (Note 2) 22 - - ----------------------------------------------------------------------- ------------------ ---------------- --------------- -- Net Income 253 189 227 Preferred Stock Cash Dividends (At stated rates) (7) (7) (8) ----------------------------------------------------------------------- ------------------ ---------------- --------------- -- Earnings Available for Common Stockholder 246 182 219 Retained Earnings at Beginning of Year 550 491 438 Common Stock Cash Dividends Declared (147) (123) (166) ======================================================================= ================== ================ =============== == Retained Earnings at End of Year $649 $550 $491 ======================================================================= ================== ================ =============== == See Notes to Consolidated Financial Statements. SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2000 1999 1998 ---------------------------------------------------------------------- ------------ ------------- ------------- (Millions of dollars) Cash Flows From Operating Activities: Net income $253 $189 $227 Adjustments to reconcile net income to net cash provided from operating activities: Cumulative effect of accounting change, net of taxes (22) - - Depreciation and amortization 159 154 131 Amortization of nuclear fuel 16 18 20 Allowance for funds used during construction (6) (6) (14) Over (under) collection, fuel adjustment clause (42) (6) 1 Changes in certain assets and liabilities: (Increase) decrease in receivables (56) (17) (13) (Increase) decrease in pension asset (43) (29) (33) (Increase) decrease in other regulatory assets 15 16 (23) (Increase) decrease inventories 8 (16) (8) Increase (decrease) in deferred income taxes, net 60 16 49 Increase (decrease) in postretirement benefits 15 11 26 Increase (decrease) in other regulatory liabilities 6 (6) 4 Increase (decrease) in accounts payable 50 (9) 35 Increase (decrease) in taxes accrued (23) (15) 30 Other, net (11) 10 9 ---------------------------------------------------------------------- ------------ ------------- ------------- Net Cash Provided From Operating Activities 379 310 441 ---------------------------------------------------------------------- ------------ ------------- ------------- Cash Flows From Investing Activities: Utility property additions and construction expenditures, net of AFC (277) (227) (252) Proceeds on sales of assets 1 3 - (Increase) decrease in nonutility property and investments (1) (6) (1) ---------------------------------------------------------------------- ------------ ------------- ------------- Net Cash Used For Investing Activities (277) (230) (253) ---------------------------------------------------------------------- ------------ ------------- ------------- Cash Flows From Financing Activities: Proceeds: Issuance of First Mortgage Bonds 148 99 - Repayment and repurchases: Mortgage bonds (100) (10) (50) Notes and loans - - (10) Other long-term debt (4) (9) - Preferred stock (1) - (1) Dividend payments: Common Stock (131) (133) (187) Preferred stock (7) (7) (8) Short-term borrowings, net (25) 88 112 Fuel financings, net - (66) (14) ---------------------------------------------------------------------- ------------ ------------- ------------- Net Cash Provided From (Used For) Financing Activities (120) (38) (158) ---------------------------------------------------------------------- ------------ ------------- ------------- Net Increase (Decrease) in Cash and Temporary Cash Investments (18) 42 30 Cash and Temporary Cash Investments, January 1 78 36 6 ====================================================================== ============ ============= ============= Cash and Temporary Cash Investments, December 31 $60 $78 $36 ====================================================================== ============ ============= ============= Supplemental Cash Flow Information: Cash paid for - Interest (net of capitalized interest of $4, $3 and $7) $102 $99 $94 - Income taxes 97 109 92 See Notes to Consolidated Financial Statements. SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION --------------------------------------------------------------------------------- ------------- ------ ------------- ------ December 31, (Millions of dollars) 2000 1999 --------------------------------------------------------------------------------- ------------- ------ ------------- ------ Common Equity (Note 8): Common stock, $4.50 par value, authorized 50,000,000 shares; issued and outstanding 40,296,147 shares $181 $181 Premium on common stock 395 395 Other paid-in capital 437 437 Capital stock expense (5) (5) Retained earnings 649 550 --------------------------------------------------------------------------------- ------------- ------ ------------- ------ Total Common Equity 1,657 54% 1,558 55% --------------------------------------------------------------------------------- ------------- ------ ------------- ------ Cumulative Preferred Stock (Not subject to purchase or sinking funds): $100 Par Value - Authorized 1,200,000 shares $50 Par Value - Authorized 125,209 shares Shares Outstanding Redemption Price Series 2000 1999 ------ ---- ---- $100 Par 6.52% 1,000,000 1,000,000 100.00 100 100 $50 Par 5.00% 125,209 125,209 52.50 6 6 --------------------------------------------------------------------------------- ------------- ------ ------------- ------ Total Preferred Stock (Not subject to purchase or sinking funds) (Note 9) 106 3% 106 4% --------------------------------------------------------------------------------- ------------- ------ ------------- ------ Cumulative Preferred Stock (Subject to purchase and sinking funds): $100 Par Value - Authorized 1,550,000 shares; None outstanding in 2000 and 1999 $50 Par Value - Authorized 1,560,287 shares Shares Outstanding Series 2000 1999 Redemption Price ------ ---- ---- ---------------- 4.50% 9,600 11,200 51.00 1 1 4.60% (A) 16,052 18,082 51.00 1 1 4.60% (B) 57,800 61,200 50.50 3 3 5.125% 67,000 68,000 51.00 3 3 6.00% 69,835 73,035 50.50 3 4 ------------- ----------- Total 220,287 231,487 ============= =========== $25 Par Value - Authorized 2,000,000 shares; None outstanding in 2000 and 1999 ---------------------------------------------------------------------------------- ------------ -------- ----------- ------- Total Preferred Stock (Subject to purchase or sinking funds) 11 12 Less: Current portion, including sinking funds requirements (1) (1) ---------------------------------------------------------------------------------- ------------ -------- ----------- ------- Total Preferred Stock, Net (Subject to purchase or sinking funds) (Notes 9 & 11) 10 -% 11 -% ---------------------------------------------------------------------------------- ------------ -------- ----------- ------- Company-Obligated Mandatorily Redeemable Preferred Securities of Company's Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount of 7.55% Junior Subordinated Debentures of SCE&G, due 2027 (Note 9) 50 2% 50 2% ---------------------------------------------------------------------------------- ------------ -------- ----------- ------- ----------------------------------------------------------- ----------- -------------- -------- -------------- ----------- December 31, (Millions of dollars) 2000 1999 ----------------------------------------------------------- ----------- -------------- -------- -------------- ----------- Long-Term Debt (Notes 5 & 11) First Mortgage Bonds: Series Year of Maturity 6% 2000 - 100 6 1/4% 2003 100 100 7.70% 2004 100 100 7 1/2% 2005 150 - 6 1/8% 2009 100 100 7 1/8% 2013 150 150 7 1/2% 2023 150 150 7 5/8% 2023 100 100 7 5/8% 2025 100 100 First and Refunding Mortgage Bonds: Series Year of Maturity 9% 2006 131 131 8 7/8% 2021 103 103 Pollution Control Facilities Revenue Bonds: Fairfield County Series 1984, due 2014 (6.50%) 57 57 Orangeburg County Series 1994, due 2024 (5.70%) 30 30 Other 17 17 Charleston Franchise Agreement due 1997-2002 7 11 Other 3 3 ----------------------------------------------------------- ----------- -------------- -------- -------------- ----------- Total Long-Term Debt 1,298 1,252 Less - Current maturities, including sinking fund requirements (28) (128) - Unamortized discount (3) (3) ----------------------------------------------------------- ----------- -------------- -------- -------------- ----------- Total Long-Term Debt, Net 1,267 41% 1,121 39% ----------------------------------------------------------- ----------- -------------- -------- -------------- ----------- Total Capitalization $3,090 100% $2,846 100% =========================================================== =========== ============== ======== ============== =========== See Notes to Consolidated Financial Statements. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. Organization and Principles of Consolidation South Carolina Electric & Gas Company (Company), a public utility, is a South Carolina corporation organized in 1924 and a wholly owned subsidiary of SCANA Corporation, a South Carolina corporation and a registered public utility holding company within the meaning of the Public Utility Holding Company Act of 1935 (PUHCA). The Company is engaged predominately in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina. The accompanying Consolidated Financial Statements reflect the accounts of the Company, South Carolina Fuel Company, Inc. (Fuel Company) and SCE&G Trust I. Intercompany balances and transactions between the Company, Fuel Company and SCE&G Trust I have been eliminated in consolidation. Affiliated Transactions The Company has entered into agreements with certain affiliates to purchase gas for resale to its distribution customers and to purchase electric energy. The Company purchases all of its natural gas requirements from Pipeline Corporation, and at December 31, 2000 and 1999, the Company had approximately $45.9 million and $20.9 million, respectively, payable to Pipeline Corporation for such gas purchases. The Company purchases all of the electric generation of Williams Station, which is owned by GENCO, under a unit power sales agreement. At December 31, 2000 and 1999 the Company had approximately $8.3 million and $9.2 million, respectively, payable to GENCO for unit power purchases. Such unit power purchases, which are included in "Purchased power," amounted to approximately $100.2 million, $105.5 million and $85.0 million in 2000, 1999 and 1998, respectively. Total interest income, based on market interest rates, associated with the Company's advances to affiliated companies was approximately $1,086,000, $921,000 and $281,000 in 2000, 1999 and 1998, respectively. B. Basis of Accounting The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71. This accounting standard requires cost-based rate-regulated utilities to recognize in their financial statements revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result the Company has recorded, as of December 31, 2000, approximately $211 million and $65 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities of approximately $129 million and $52 million, respectively. The electric and gas regulatory assets of approximately $45 million and $37 million, respectively (excluding deferred income tax assets) are recoverable through rates. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company's results of operations in the period the write-off would be recorded, but it is not expected that cash flows or financial position would be materially affected. C. System of Accounts The accounting records of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and as adopted by the South Carolina Public Service Commission (PSC). D. Utility Plant Utility plant is stated substantially at original cost. The costs of additions, renewals and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and an allowance for funds used during construction, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged, along with the cost of removal, less salvage, to accumulated depreciation. The costs of repairs, replacements and renewals of items of property determined to be less than a unit of property are charged to maintenance expense. The Company, operator of the V. C. Summer Nuclear Station (Summer Station), and the South Carolina Public Service Authority (Santee Cooper) are joint owners of Summer Station in the proportions of two-thirds and one-third, respectively. The parties share the operating costs and energy output of the plant in these proportions. Each party, however, provides its own financing. Plant-in-service related to the Company's portion of Summer Station was approximately $965.0 million and $959.7 million as of December 31, 2000 and 1999, respectively. Accumulated depreciation associated with the Company's share of Summer Station was approximately $387.7 million and $365.1 million as of December 31, 2000 and 1999, respectively. The Company's share of the direct expenses associated with operating Summer Station is included in "Other operation and maintenance" expenses. E. Allowance for Funds Used During Construction (AFC) AFC, a noncash item, reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company has calculated AFC using composite rates of 8.1%, 7.7% and 8.5% for 2000, 1999 and 1998, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. Interest on nuclear fuel in process is capitalized at the actual interest amount incurred. F. Revenue Recognition Revenues are recorded during the accounting period in which services are provided to customers, and include estimated amounts for electricity and natural gas delivered but not yet billed. Prior to January 1, 2000 revenues related to regulated electric and gas services were recorded only as customers were billed (see Note 2). Fuel costs for electric generation are collected through the fuel cost component in retail electric rates. The fuel cost component contained in electric rates is established by the PSC during annual fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is deferred and included when determining the fuel cost component during the next annual fuel cost hearing. The Company had undercollected through the electric fuel cost component approximately $35.5 million and $10.1 million at December 31, 2000 and 1999, respectively, which are included in "Deferred Debits - Other regulatory assets." 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 costs and amounts contained in rates is deferred and included when establishing gas costs during the next annual gas cost recovery hearing. At December 31, 2000 and 1999 the Company had undercollected through the gas cost recovery procedure approximately $12.7 million and $4.1 million, respectively, which are included in "Deferred Debits Other regulatory assets." The Company's gas rate schedules for residential, small commercial and small industrial customers include a weather normalization adjustment, which minimizes fluctuations in gas revenues due to abnormal weather conditions. G. Depreciation and Amortization Provisions for depreciation and amortization are recorded using the straight-line method and are based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were 2.98%, 2.99% and 3.02% for 2000, 1999 and 1998, respectively. Nuclear fuel amortization, which is included in "Fuel used in electric generation" and recovered through the fuel cost component of the Company's rates, is recorded using the units-of-production method. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the Department of Energy (DOE) under a contract for disposal of spent nuclear fuel. H. Nuclear Decommissioning The Company's share of estimated site-specific nuclear decommissioning costs for Summer Station, including the cost of decommissioning plant components not subject to radioactive contamination, totals approximately $357.3 million, stated in 1999 dollars, based on a decommissioning study completed in 2000. Santee Cooper is responsible for decommissioning costs related to its ownership interest in the station. The cost estimate is based on a decommissioning methodology acceptable to the Nuclear Regulatory Commission (NRC) under which the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that permits release for unrestricted use. The Company's method of funding decommissioning costs is referred to as COMReP (Cost of Money Reduction Plan). Under this plan, funds collected through rates ($3.2 million in each of 2000, 1999 and 1998) are used to pay premiums on insurance policies on the lives of certain Company personnel. The Company is the beneficiary of these policies. Through these insurance contracts, the Company is able to take advantage of income tax benefits and accrue earnings on the fund on a tax-deferred basis. Amounts for decommissioning collected through electric rates, insurance proceeds, and interest on proceeds, less expenses, are transferred by the Company to an external trust fund in compliance with the financial assurance requirements of the NRC. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis. The Company records its liability for decommissioning costs in deferred credits. In addition to the above, pursuant to the National Energy Policy Act passed by Congress in 1992 and the requirements of the DOE, the Company has recorded a liability for its estimated share of the DOE's decontamination and decommissioning obligation. The liability, approximately $2.8 million at December 31, 2000, has been included in "Long-Term Debt, net." The Company is recovering the cost associated with this liability through the fuel cost component of its rates; accordingly, this amount has been deferred and is included in "Deferred Debits - Other." I. Income Taxes The Company is included in the consolidated federal income tax return of SCANA Corporation. Under a joint consolidated income tax allocation agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers; otherwise, they are charged or credited to income tax expense. J. 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. K. Environmental The Company maintains an environmental assessment program to identify and assess current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate primarily to regulated operations. Such amounts are deferred and amortized with recovery provided through rates. The Company also has recovered portions of its environmental liabilities through settlements with various insurance carriers, including all amounts previously deferred for its electric operations. The Company expects to recover all deferred amounts related to its gas operations by December 2005. Deferred amounts, net of amounts recovered through rates and insurance settlements, totaled $20.2 million and $23.7 million at December 31, 2000 and 1999, respectively. The deferral includes the estimated costs associated with the matters discussed in Note 12C. L. Fuel Inventories Nuclear fuel and fossil fuel inventories and sulfur dioxide emission allowances are purchased and financed by Fuel Company under a contract which requires the Company to reimburse Fuel Company for all costs and expenses relating to the ownership and financing of fuel inventories and sulfur dioxide emission allowances. Accordingly, such fuel inventories and emission allowances and fuel-related assets and liabilities are included in the Company's consolidated financial statements. (See Note 6.) M. 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. N. Recently Issued Accounting Standard and Bulletin In June 1998 the Financial Accounting Standards Board (FASB) issued SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." In June 2000 the FASB issued SFAS 138, which amends certain provisions of SFAS 133 to expand the normal purchase and sale exemption for supply contracts and to redefine interest rate risk to reduce sources of ineffectiveness, among other things. The Company's adoption of SFAS 133, as amended, on January 1, 2001 did not have a material impact on the Company's results of operations, cash flows or financial position. In December 1999 Staff Accounting Bulletin No. 101, "Revenue Recognition in Financial Statements" was issued by the Securities and Exchange Commission (SEC), and provides the SEC staff's views in applying generally accepted accounting principles to selected revenue recognition issues. The Company's adoption of this bulletin in the fourth quarter of 2000 had no impact on its results of operations, cash flows or financial position. O. Reclassifications Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2000. P. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. 2. Cumulative Effect of Accounting Change Effective January 1, 2000 the Company changed its method of accounting for operating revenues from cycle billing to full accrual. The cumulative effect of this change was $22 million, net of tax. Accruing unbilled revenues more closely matches revenues and expenses. Unbilled revenues represent the estimated amount customers will be charged for service rendered but not yet billed as of the end of the accounting period. If this method had been applied retroactively, net income would have been $191 million and $220 million for the years ended December 31, 1999 and 1998, respectively, compared to $189 million and $227 million, respectively, as reported. 3. RATE AND OTHER REGULATORY MATTERS A. On July 20, 2000 the PSC issued an order approving the Company's request for an out-of-period adjustment to increase the cost of gas component of its rates for natural gas service from 54.334 cents per therm to 68.835 cents per therm, effective with the first billing cycle in August 2000. As part of its regularly scheduled annual review of gas costs, the PSC issued an order on November 9, 2000 which further increased the cost of gas component to 78.151 cents per therm, effective with the first billing cycle in November 2000. On December 21, 2000 the PSC issued an order approving the Company's request for another out-of-period adjustment to increase the cost of gas component to 99.340 cents per therm, effective with the first billing cycle in January 2001. B. On July 5, 2000 the PSC approved the Company's request to implement lower depreciation rates for its gas operations. The new rates were effective retroactively to January 1, 2000 and resulted in a reduction in annual depreciation expense of approximately $2.9 million. C. On September 14, 1999 the PSC approved an accelerated capital recovery plan for the Company's Cope Generating Station. The plan was implemented beginning January 1, 2000 for a three-year period. The PSC approved an accelerated capital recovery methodology wherein the Company may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates. The amount of the accelerated depreciation will be determined by the Company based on the level of revenues and operating expenses, not to exceed $36 million annually without the approval of the PSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year. As of December 31, 2000 no accelerated depreciation has been recorded. The accelerated capital recovery plan will be accomplished through existing customer rates. D. On December 11, 1998 the PSC issued an order requiring the Company to reduce retail electric rates on a prospective basis. The PSC acted in response to the Company reporting that it earned a 13.04 percent return on common equity for its retail electric operations for the 12 months ended September 30, 1998. This return on common equity exceeded the Company's authorized return of 12.0 percent by 1.04 percent, or $22.7 million, primarily as a result of record heat experienced during the summer. The order required prospective rate reductions on a per kilowatt-hour basis, based on actual retail sales for the 12 months ended September 30, 1998. On January 12, 1999 the PSC denied the Company's motion for reconsideration, ruled that no further rate action was required, and reaffirmed the Company's authorized return on equity of 12.0 percent. The rate reductions were placed into effect with the first billing cycle of January 1999. E. On January 9, 1996 the PSC issued an order granting the Company an increase in retail electric rates which were fully implemented by January 1997. The PSC authorized a return on common equity of 12.0 percent. The PSC also approved establishment of a Storm Damage Reserve Account capped at $50 million to be collected through rates over a ten-year period. Additionally, the PSC approved accelerated recovery of a significant portion of the Company's electric regulatory assets (excluding deferred income tax assets) and the remaining transition obligation for postretirement benefits other than pensions, changing the amortization periods to allow recovery by the end of the year 2000. The Company's request to shift, for rate-making purposes, approximately $257 million of depreciation reserves from transmission and distribution assets to nuclear production assets was also approved. The Consumer Advocate and two other intervenors appealed certain issues in the order initially to the Circuit Court, which affirmed the PSC's decisions, and subsequently, to the Supreme Court. In March 1998 the Company, the PSC, the Consumer Advocate and one of the other intervenors reached an agreement that provided for the reversal of the shift in depreciation reserves and the dismissal of the appeal of all other issues. The PSC also authorized the Company to adjust depreciation rates that had been approved in the 1996 rate order for its electric transmission, distribution and nuclear production properties to eliminate the effect of the depreciation reserve shift and to retroactively apply such depreciation rates to February 1996. As a result, a one-time reduction in depreciation expense of $9.8 million was recorded in March 1998. The agreement does not affect retail electric rates. The FERC had previously rejected the transfer of depreciation reserves for rates subject to its jurisdiction. In September 1998 the Supreme Court affirmed the Circuit Court's rulings on the issues contested by the remaining intervenor. F. In 1994 the PSC issued an order approving the Company's request to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former manufactured gas plants (MGPs). The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for the Company's gas operations that had previously been deferred. In November 2000, as a result of the annual review, the PSC approved the Company's request to maintain the billing surcharge at $.011 per therm to provide for the recovery of the remaining balance of $20.1 million. G. In September 1992 the PSC issued an order granting the Company's request for a $.25 increase in transit fares from $.50 to $.75 in Columbia, South Carolina; however, the PSC also required $.40 fares for low income customers and denied the Company's request to reduce the number of routes and frequency of service. The new rates were placed into effect in October 1992. The Company appealed the PSC's order to the Circuit Court, which in May 1995 ordered the case back to the PSC for reconsideration of several issues including the low income rider program, routing changes, and the $.75 fare. The Supreme Court declined to review an appeal of the Circuit Court decision and dismissed the case. The PSC and other intervenors filed another Petition for Reconsideration, which the Supreme Court denied. The PSC and other intervenors filed another appeal to the Circuit Court which the Circuit Court denied in an order dated May 9, 1996. In this order, the Circuit Court upheld its previous orders and remanded them to the PSC. During August 1996 the PSC heard oral arguments on the orders on remand from the Circuit Court. On September 30, 1996 the PSC issued an order affirming its previous orders and denied the Company's request for reconsideration. In response to an appeal of the PSC's order by the Company, the Circuit Court issued an order on May 25, 2000, which remanded the matter to the PSC for review of the Company's original application and request to terminate the low income rider fare. On September 27, 2000 the PSC issued an order granting the relief requested by the Company. On September 29, 2000 the Consumer Advocate filed a motion with the PSC for a stay of this order, to which the Company filed a response. On October 3, 2000 the PSC accepted the Consumer Advocate's motion and issued a stay of its order. The Consumer Advocate and other intervenors have petitioned the Circuit Court for judicial review of the PSC's order granting relief. Action by the Circuit Court is pending. 4. EMPLOYEE BENEFIT PLANS The Company participates in SCANA's noncontributory defined benefit pension plan, which covers substantially all permanent employees. SCANA's policy has been to fund the plan to the extent permitted by the applicable Federal income tax regulations as determined by an independent actuary. Effective July 1, 2000, SCANA's pension plan was amended to provide a cash balance formula. With certain exceptions, employees were allowed to either remain under the final average pay formula or elect the cash balance formula. Under the final average pay formula, benefits are based on years of accredited service and the employee's average annual base earnings received during the last three years of employment. Under the cash balance formula, the monthly benefit earned under the final average pay formula at July 1, 2000 was converted to a lump sum amount for each employee and increased by transition credits for eligible employees. Under the cash balance formula, benefits based upon this opening balance increase going forward as a result of compensation credits and interest credits. The effect of this plan amendment was to reduce the Company's net periodic benefit income for the year ended December 31, 2000 by approximately $3.4 million. In addition to pension benefits, the Company provides certain unfunded health care and life insurance benefits to active and retired employees. Retirees share in a portion of their medical care cost. The Company provides life insurance benefits to retirees at no charge. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for the applicable benefits. Additionally, to accelerate the amortization of the remaining transition obligation for postretirement benefits other than pensions, as authorized by the PSC, the Company expensed approximately $0.7 million and $15.7 million for the years ended December 31, 1999 and 1998, respectively. (See Note 3E.) Effective July 1, 2000, PSNC's pension and postretirement benefit plans were merged with SCANA's plans. At the time of the merger of the plans, PSNC had recorded a prepaid pension cost of approximately $9.0 million and a postretirement welfare plan obligation of approximately $9.1 million in its consolidated balance sheet. Disclosures required for these plans under SFAS 132, "Employer's Disclosures about Pensions and Other Postretirement Benefits" are set forth in the following tables: Components of Net Periodic Benefit Cost Retirement Benefits Other Postretirement Benefits --------------------------------------- --------------------------------------- Millions of dollars 2000 1999 1998 2000 1999 1998 --------------------------------- ---------- --------------- ------------ -- ---------------- ------------ --------- Service Cost $8.3 $10.0 $8.3 $2.7 $3.0 $2.6 Interest Cost 33.5 27.9 25.9 10.2 9.5 9.4 Expected return on assets (76.6) (65.5) (59.3) n/a n/a n/a Prior service cost amortization 3.0 1.1 1.1 0.8 0.7 0.7 Actuarial (gain) loss (12.2) (8.6) (9.6) - 1.2 1.0 Transition amount amortization 0.8 0.8 0.8 0.8 1.7 19.1 Special termination benefit cost - 5.5 - - 1.0 - Amount attributable to Company affiliates 1.7 1.1 0.3 (1.6) (0.9) (0.7) ================================= ========== =============== ============ == ================ ============ ========= Net periodic benefit (income) cost $(41.5) $(27.7) $(32.5) $12.9 $16.2 $32.1 ================================= ========== =============== ============ == ================ ============ ========= Weighted-Average Assumptions Retirement Benefits Other Postretirement Benefits --------------------------------------- --------------------------------------- As of December 31 2000 1999 1998 2000 1999 1998 --------------------------------- ------------ ------------- ------------ -- ---------------- ------------ --------- Discount rate 8.0% 8.0% 7.0% 8.0% 8.0% 7.0% Expected return on plan assets 9.5% 9.5% 9.5% n/a n/a n/a Rate of compensation increase 4.0% 4.0% 4.0% 4.0% 4.0% 4.0% Changes in Benefit Obligation Retirement Benefits Other Postretirement Benefits ------------------------------- --------------------------------------- Millions of dollars 2000 1999 2000 1999 --------------------------------- ---------------- -------------- -- ----------------- --------------------- --------------------------------- ---------------- -------------- -- ----------------- --------------------- Benefit obligation, January 1 $362.3 $389.3 $129.8 $137.0 Service cost 8.3 10.0 2.7 3.0 Interest cost 33.5 27.9 10.2 9.5 Plan participants' contributions 0.1 0.1 0.5 0.5 Plan amendment 65.4 - 0.9 - Actuarial (gain) loss 1.6 (51.6) (7.8) (14.5) Acquisition/merger of plans 39.8 - 11.2 - Benefits paid (31.7) (18.9) (8.5) (6.7) Special termination benefit cost - 5.5 - 1.0 ================================= ================ ============== == ================= ===================== Benefit obligation, December 31 $479.3 $362.3 $139.0 $129.8 ================================= ================ ============== == ================= ===================== Change in Plan Assets Retirement Benefits ------------------------------------------------- ---------------------------- -------------------------- Millions of dollars 2000 1999 ------------------------------------------------- ---------------------------- -------------------------- Fair value of plan, assets, January 1 $783.0 $698.8 Actual return on plan assets 96.7 103.0 Company contribution - - Plan participants' contributions 0.1 0.1 Acquisition/merger of plans 46.2 - Benefits paid (31.7) (18.9) ------------------------------------------------- ---------------------------- -------------------------- Fair value of plan assets, December 31 $894.3 $783.0 ================================================= ============================ ========================== Funded Status of Plans Retirement Benefits Other Postretirement Benefits --------------------------------- Millions of dollars 2000 1999 2000 1999 ------------------------------------------ ------------ -------------- ---- --------------- ----------------- Funded status, December 31 $415.0 $420.7 $(139.0) $(129.8) Unrecognized actuarial (gain) loss (297.6) (294.0) 13.0 18.8 Unrecognized prior service cost 73.7 11.4 4.5 4.3 Unrecognized net transition obligation 4.8 5.6 8.3 9.1 ------------------------------------------ ------------ -------------- ---- --------------- ----------------- Net asset (liability) recognized in Consolidated Balance Sheet $195.9 $143.7 $(113.2) $(97.6) ========================================== ============ ============== ==== =============== ================= Health Care Trends The determination of net periodic other postretirement benefit cost is based on the following assumptions: 2000 1999 1998 ------------------------------------------ ---------- ---------- ---------- Health care cost trend rate 7.5% 8.0% 8.5% Ultimate health care cost trend rate 5.5% 5.5% 5.0% Year achieved 2005 2005 2005 The effect of a one-percentage-point increase or decrease in the assumed health care cost trend rates on the aggregate of the service and interest cost components of net periodic postretirement health care benefit cost and the accumulated other postretirement benefit obligation for health care benefits are as follows: 1% 1% Millions of dollars Increase Decrease ------------------ ----------------- Effect on health care cost $0.2 $(0.3) Effect on postretirement obligation 2.9 (3.4) 5. LONG-TERM DEBT The annual amounts of long-term debt maturities and sinking fund requirements for the years 2001 through 2005 are summarized as follows: ----------------- ----------------- ------------------ ----------------- Year Amount Year Amount ----------------- ----------------- ------------------ ----------------- (Millions of Dollars) 2001 $27.6 2004 $123.9 2002 27.6 2005 173.9 2003 129.8 ----------------- ----------------- ------------------ ----------------- Approximately $23.5 million of the portion of long-term debt payable in 2001 may be satisfied by either deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits, or by deposit of cash with the Trustee. On August 7, 1996 the City of Charleston executed 30-year electric and gas franchise agreements with the Company. In consideration for the electric franchise agreement, the Company is paying the City $25 million over seven years (1996-2002) and has donated to the City the existing transit assets in Charleston. The $25 million is included in electric plant-in-service. In settlement of environmental claims the City may have had against the Company involving the Calhoun Park area, where the Company and its predecessor companies operated a MGP until the 1960's, the Company paid the City $26 million over a four-year period (1996-1999). The Company has three-year revolving lines of credit totaling $75 million, in addition to other lines of credit, that provide liquidity for issuance of commercial paper. The three-year lines of credit provide back-up liquidity when commercial paper outstanding is in excess of $175 million. The long-term nature of the lines of credit allow commercial paper in excess of $175 million to be classified as long-term debt. The Company's commercial paper outstanding totaled $117.5 million and $143.1 million at December 31, 2000 and 1999, at weighted average interest rates of 6.59 percent and 6.63 percent, respectively. Substantially all utility plant is pledged as collateral in connection with long-term debt. 6. FUEL FINANCINGS Nuclear and fossil fuel inventories and sulfur dioxide emission allowances are financed through the issuance by Fuel Company of short-term commercial paper. These short-term borrowings are supported by a 364-day revolving credit agreement which expires December 19, 2001. The credit agreement provides for a maximum amount of $125 million to be outstanding at any time. Since the credit agreement expires within one year, commercial paper amounts outstanding have been classified as short-term debt. Commercial paper outstanding totaled $70.2 million at December 31, 2000 and 1999 at weighted average interest rates of 6.59 percent and 6.44 percent, respectively. 7. SHORT-TERM BORROWINGS The Company pays fees to banks as compensation for its committed lines of credit. Commercial paper borrowings are for 270 days or less. Details of lines of credit (including uncommitted lines of credit) and short-term borrowings, excluding amounts classified as long-term (Note 5 ), at December 31, 2000 and 1999, are as follows: Millions of dollars 2000 1999 ------------------------------------------------------------- --------------- Authorized lines of credit at year-end $375.0 $410.0 Unused lines of credit at year-end $375.0 $410.0 Short-term borrowings outstanding at year-end: Commercial paper $187.7 $213.3 Weighted average interest rate 6.59% 6.63% 8. RETAINED EARNINGS The Restated Articles of Incorporation of the Company and the Indenture underlying its First and Refunding Mortgage Bonds contain provisions that, under certain circumstances, could limit the payment of cash dividends on common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2000 approximately $32.7 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock. 9. PREFERRED STOCK The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend. Retirements under sinking fund requirements are at par values. The aggregate annual amount of purchase fund or sinking fund requirements for preferred stock for the years 2001 through 2005 is $2.8 million. The changes in "Total Preferred Stock (Subject to purchase or sinking funds)" during 2000, 1999 and 1998 are summarized as follows: Number of Shares Millions of Dollars -------------------------------------------------------- ----------------------- Balance at December 31, 1997 251,094 $12.5 Shares Redeemed - $50 par value (11,042) (0.5) -------------------------------------------------------- ----------------------- Balance at December 31, 1998 240,052 12.0 Shares Redeemed - $50 par value (8,565) (0.4) -------------------------------------------------------- ----------------------- Balance at December 31, 1999 231,487 11.6 Shares Redeemed - $50 par value (11,200) (0.6) -------------------------------------------------------- ----------------------- Balance at December 31, 2000 220,287 $11.0 ======================================================== ======================= On October 28, 1997 SCE&G Trust I (the "Trust"), a wholly-owned subsidiary of the Company, issued $50 million (2,000,000 shares) of 7.55 percent Trust Preferred Securities, Series A (the "Preferred Securities"). The Company owns all of the Common Securities of the Trust (the "Common Securities"). The Preferred Securities and the Common Securities (the "Trust Securities") represent undivided beneficial ownership interests in the assets of the Trust. The Trust exists for the sole purpose of issuing the Trust Securities and using the proceeds thereof to purchase from the Company its 7.55 percent Junior Subordinated Debentures due September 30, 2027. The sole asset of the Trust is $50.0 million of Junior Subordinated Debentures of the Company. Accordingly, no financial statements of the Trust are presented. The Company's obligations under the Guarantee Agreement entered into in connection with the Preferred Securities, when taken together with the Company's obligation to make interest and other payments on the Junior Subordinated Debentures issued to the Trust and the Company's obligations under the Indenture pursuant to which the Junior Subordinated Debentures were issued, provides a full and unconditional guarantee by the Company of the Trust's obligations under the Preferred Securities. Proceeds were used to redeem preferred stock of the Company. The preferred securities of the Trust are redeemable only in conjunction with the redemption of the related 7.55 percent Junior Subordinated Debentures. The Junior Subordinated Debentures will mature on September 30, 2027 and may be redeemed, in whole or in part, at any time on or after September 30, 2002 or upon the occurrence of a Tax Event. A Tax Event occurs if an opinion is received from counsel experienced in such matters that there is more than an insubstantial risk that: (1) the Trust is or will be subject to Federal income tax, with respect to income received or accrued on the Junior Subordinated Debentures, (2) interest payable by the Company on the Junior Subordinated Debentures will not be deductible, in whole or in part, by the Company for Federal income tax purposes, or (3) the Trust will be subject to more than a de minimis amount of other taxes, duties, or other governmental charges. Upon the redemption of the Junior Subordinated Debentures, payment will simultaneously be applied to redeem Preferred Securities having an aggregate liquidation amount equal to the aggregate principal amount of the Junior Subordinated Debentures. The Preferred Securities are redeemable at $25 per preferred security plus accrued distributions. 10. INCOME TAXES Total income tax expense attributable to income before cumulative effect of accounting change for 2000, 1999 and 1998 is as follows: Millions of dollars 2000 1999 1998 ------------------------------------------------------------ ----------------- ----------------- Current taxes: Federal $78.4 $91.3 $116.1 State 7.8 0.3 2.1 ------------------------------------------------------------ ----------------- ----------------- ------------------------------------------------------------ ----------------- ----------------- Total current taxes 86.2 91.6 118.2 ------------------------------------------------------------ ----------------- ----------------- ------------------------------------------------------------ ----------------- ----------------- Deferred taxes, net: Federal 31.8 7.7 1.8 State 5.2 1.4 2.0 ------------------------------------------------------------ ----------------- ----------------- ------------------------------------------------------------ ----------------- ----------------- Total deferred taxes 37.0 9.1 3.8 ------------------------------------------------------------ ----------------- ----------------- ------------------------------------------------------------ ----------------- ----------------- Investment tax credits: Deferred - State 5.0 13.4 14.3 Amortization of amounts deferred - State (1.3) (1.2) (0.9) Amortization of amounts deferred - Federal (3.2) (3.2) (3.2) ------------------------------------------------------------ ----------------- ----------------- Total investment tax credits 0.5 9.0 10.2 ------------------------------------------------------------ ----------------- ----------------- Non-conventional fuel tax credits: Deferred - Federal 9.4 n/a n/a ------------------------------------------------------------ ----------------- ----------------- Total income tax expense 133.1 $109.7 $132.2 ============================================================ ================= ================= The difference between actual income tax expense and the amount calculated from the application of the statutory Federal income tax rate (35% for 2000, 1999 and 1998) to pre-tax income before cumulative effect of accounting change is reconciled as follows: Millions of dollars 2000 1999 1998 --------------------------------------------------------------- ----------------- ----------------- ----------------- Income before cumulative effect of accounting change $223.9 $181.8 $219.7 Total income tax expense: Charged to operating expense 123.8 103.1 127.9 Charged to other items 9.3 6.6 4.2 Preferred stock dividends 7.4 7.4 7.5 --------------------------------------------------------------- ----------------- ----------------- ----------------- Total pre-tax income $364.4 $298.9 $359.3 =============================================================== ================= ================= ================= =============================================================== ================= ================= ================= Income taxes on above at statutory Federal income tax rate $127.5 $104.6 $125.8 Increases (decreases) attributed to: State income taxes (less Federal income tax effect) 10.9 9.0 11.4 Amortization of Federal investment tax credits (3.2) (3.2) (3.2) Other differences, net (2.1) (0.7) (1.8) --------------------------------------------------------------- ----------------- ----------------- ----------------- =============================================================== ================= ================= ================= Total income tax expense $133.1 $109.7 $132.2 =============================================================== ================= ================= ================= The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $604.1 million at December 31, 2000 and $544.8 million at December 31, 1999 (see Note 1I), are as follows: Millions of dollars 2000 1999 --------------------------------------------------------------------------------- ---------------- ------------------ Deferred tax assets: Unamortized investment tax credits $57.3 $57.9 Other postretirement benefits 40.6 36.6 Early retirement programs 14.6 14.8 Deferred compensation 8.6 8.6 Cycle billing - 15.5 Other 7.7 11.1 --------------------------------------------------------------------------------- ---------------- ------------------ Total deferred tax assets 128.8 144.5 --------------------------------------------------------------------------------- ---------------- ------------------ Deferred tax liabilities: Property, plant and equipment 609.5 593.5 Pension plan benefit income 65.3 50.7 Research and experimentation costs 26.8 27.3 Deferred fuel costs 18.5 5.5 Cycle billing 1.9 - Other 10.9 12.3 --------------------------------------------------------------------------------- ---------------- ------------------ Total deferred tax liabilities 732.9 689.3 --------------------------------------------------------------------------------- ---------------- ------------------ Net deferred tax liability $604.1 $544.8 ================================================================================= ================ ================== The Internal Revenue Service has examined and closed consolidated Federal income tax returns of SCANA through 1995, has examined and proposed adjustments to SCANA's 1996 and 1997 Federal returns, and is currently examining SCANA's Federal returns for 1998 and 1999. The Company does not anticipate that any adjustments which might result from these examinations will have a significant impact on its results of operations, cash flows or financial position. 11. FINANCIAL INSTRUMENTS The carrying amounts and estimated fair values of the Company's financial instruments at December 31, 2000 and 1999 are as follows: Millions of dollars 2000 1999 -------------------------------------------------------- ---------------------- -------------------------- Estimated Estimated Carrying Fair Carrying Fair Amount Value Amount Value -------------------------------------------------------- ----------- ------------ ------------ ----------- Assets: Cash and temporary cash investments $60.2 $60.2 $78.4 $78.4 Investments 6.4 6.4 4.7 4.7 Liabilities: Short-term borrowings 187.7 187.7 213.3 213.3 Long-term debt 1,294.1 1,331.6 1,248.6 1,232.7 Preferred stock (subject to purchase or sinking funds) 11.0 8.7 11.6 8.5 -------------------------------------------------------- ----------- ------------ ------------ ----------- The information presented herein is based on pertinent information available as of December 31, 2000 and 1999. 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, 2000, 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: o Cash and temporary cash investments, including commercial paper, repurchase agreements, treasury bills and notes, are valued at their carrying amount. o Fair values of investments and long-term debt are based on quoted market prices of the instruments or similar instruments. For debt instruments for which there are no quoted market prices available, fair values are based on net present value calculations. For investments for which the fair value is not readily determinable, fair value approximates cost. Settlement of long-term debt may not be possible or may not be considered prudent. o Short-term borrowings are valued at their carrying amount. o The fair value of preferred stock (subject to purchase or sinking funds) is estimated on the basis of market prices. o Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been taken into consideration. 12. COMMITMENTS AND CONTINGENCIES: A. Lake Murray Dam Reinforcement On October 15, 1999 FERC notified the Company of its agreement with the Company's plan to reinforce Lake Murray Dam in order to maintain the lake in case of an extreme earthquake. The Company and FERC have been discussing possible reinforcement alternatives for the dam over the past several years as part of the Company's ongoing hydroelectric operating license with FERC. Until discussions are concluded, it is not possible to finalize the cost of the project; however, it is possible that the cost could range up to $250 million. Although any costs incurred by the Company are expected to be recoverable through electric rates, the Company also is exploring alternative sources of funding. The project is expected to be completed in 2004. 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 $9.5 billion. Each reactor licensee is currently liable for up to $88.1 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $10 million of the liability per reactor would be assessed per year. The Company's maximum assessment, based on its two-thirds ownership of Summer Station, would be approximately $58.7 million per incident, but not more than $6.7 million per year. The Company currently maintains policies (for itself and on behalf of Santee Cooper) with Nuclear Electric Insurance Limited (NEIL). The policies covering the nuclear facility for property damage, excess property damage and outage cost permit assessments under certain conditions to cover insurer's losses. Based on the current annual premium, the Company's portion of the retroactive premium assessment would not exceed $8.1 million. To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that the Company's rates would not recover the cost of any purchased replacement power, the Company will retain the risk of loss as a self-insurer. The Company has no reason to anticipate a serious nuclear incident at Summer Station. If such an incident were to occur, it could have a material adverse impact on the Company's results of operations, cash flows and financial position. C. Environmental In September 1992 the Environmental Protection Agency (EPA) notified the Company, the City of Charleston and the Charleston Housing Authority of their potential liability for the investigation and cleanup of the Calhoun Park area site in Charleston, South Carolina. This site encompasses approximately 30 acres and includes properties which were locations for industrial operations, including a wood preserving (creosote) plant, one of the Company's decommissioned manufactured gas plants (MGP), properties owned by the National Park Service and the City of Charleston, and private properties. The site has not been placed on the National Priorities List, but may be added in the future. The Potentially Responsible Parties (PRPs) negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study and a corresponding Scope of Work. Field work began in November 1993, and the EPA approved a Remedial Investigation Report in February 1997 and a Feasibility Study Report in June 1998. In July 1998 the EPA approved the Company's Removal Action Work Plan for soil excavation. The Company completed Phase One of the Removal Action Work Plan in 1998 at a cost of approximately $1.5 million. Phase Two, which cost approximately $3.5 million, included excavation and installation of several permanent barriers to mitigate coal tar seepage. On September 30, 1998 a Record of Decision was issued which sets forth the EPA's view of the extent of each PRP's responsibility for site contamination and the level to which the site must be remediated. The Company estimates that the Record of Decision will result in costs of approximately $13.3 million, of which approximately $2 million remains. On January 13, 1999 the EPA issued a Unilateral Administrative Order for Remedial Design and Remedial Action directing the Company to design and carry out a plan of remediation for the Calhoun Park site. The Company submitted a Comprehensive Remedial Design Work Plan (RDWP) on December 17, 1999 and proceeded with implementation pending agency approval. The RDWP was approved by the EPA in July 2000, and its implementation continues. In October 1996 the City of Charleston and the Company settled all environmental claims the City may have had against the Company involving the Calhoun Park area for a payment of $26 million over four years (1996-1999) by the Company to the City. The Company is recovering the amount of the settlement, which does not encompass site assessment and cleanup costs, through rates in the same manner as other amounts accrued for site assessments and cleanup as discussed above. As part of the environmental settlement, the Company constructed an 1,100 space parking garage on the Calhoun Park site (construction was completed in April 2000) and transferred the facility to the City in exchange for a $16.5 million, 18-year municipal bond collateralized by revenues from, and a mortgage on, the parking garage. The Company owns three other decommissioned MGP sites which contain residues of by-product chemicals. For the site located in Sumter, South Carolina, effective September 15, 1998, the Company entered into a Remedial Action Plan Contract with DHEC pursuant to which it agreed to undertake a full site investigation and remediation under the oversight of DHEC. Site investigation and characterization are proceeding according to schedule. Upon selection and successful implementation of a site remedy, DHEC will give the Company a Certificate of Completion, and a covenant not to sue. For the site located in Florence, South Carolina, the Company entered into a similar Remedial Action Plan Contract with DHEC effective September 5, 2000. The Company is continuing to investigate the remaining site in Columbia, and is monitoring the nature and extent of residual contamination. D. Franchise Agreement See Note 5 for a discussion of the electric franchise agreement between SCE&G and the City of Charleston. E. Claims and Litigation SCANA and Westvaco each own a 50 percent interest in Cogen South LLC (Cogen). Cogen was formed to build and operate a cogeneration facility at Westvaco's Kraft Division Paper Mill in North Charleston, South Carolina. The facility began operations in March 1999. On September 10, 1998 the contractor in charge of construction filed suit in South Carolina Circuit Court seeking approximately $52 million from Cogen, alleging that it incurred construction cost overruns relating to the facility and that the construction contract provides for recovery of these costs. In addition to Cogen, Westvaco, the Company and SCANA were also named as defendants in the suit. The Company and the other defendants believe the suit is without merit and are mounting an appropriate defense. The Company does not believe that the resolution of this issue will have a material impact on its results of operations, cash flows or financial position. The Company is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company. 13. SEGMENT OF BUSINESS INFORMATION The Company's reportable segments, based on combined revenues from external and internal sources, are Electric Operations and Gas Distribution. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company records intersegment sales and transfers of electricity and gas based on rates established by the appropriate regulatory authority. Non-regulated sales and transfers are recorded at current market prices. Electric Operations is comprised of the electric portion of the Company and Fuel Company and is primarily engaged in the generation, transmission, and distribution of electricity. The Company's electric service territory extends into 24 counties covering more than 15,000 square miles in the central, southern, and southwestern portions of South Carolina. Sales of electricity to industrial, commercial, and residential customers are regulated by the PSC and the FERC. Fuel Company acquires, owns, and provides financing for the fuel and emission allowances required for the operation of the Company's generation facilities. Gas Distribution, comprised of the local distribution operations of the Company, is engaged in the purchase and sale, primarily at retail, of natural gas. The Company's operations extend to 31 counties in South Carolina covering approximately 21,000 square miles. The Company's reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However, Electric Operation's product differs from Gas Distribution, as does its generation process and method of distribution. Disclosure of Reportable Segments Millions of dollars -------------------------------- ------------- -------------- ----------- ---------------- ------------------ Electric Gas All Adjustments/ Consolidated 2000 Operations Distribution Other Eliminations Total -------------------------------- ------------- -------------- ----------- ---------------- ------------------ External Customer Revenue $1,344 $325 $1 $(1) $1,669 Intersegment Revenue 218 2 - (220) - Operating Income (Loss) 430 31 - (4) 457 Interest Expense 5 n/a 4 96 105 Depreciation & Amortization 147 11 - - 158 Assets 4,655 416 - (407) 4,664 Expenditures for Assets 227 19 - 32 278 Deferred Tax Assets - n/a - - - -------------------------------- ------------- -------------- ----------- ---------------- ------------------ Electric Gas All Adjustments/ Consolidated 1999 Operations Distribution Other Eliminations Total -------------------------------- ------------ --------------- ----------- ---------------- ------------------ External Customer Revenue $1,226 $239 $2 $(2) $1,465 Intersegment Revenue 203 2 - (205) - Operating Income (Loss) 376 22 - (5) 393 Interest Expense 5 n/a 4 93 102 Depreciation & Amortization 140 13 - - 153 Segment Assets 4,452 399 6 (453) 4,404 Expenditures for Assets 198 19 - 16 233 Deferred Tax Assets 2 n/a - 14 16 -------------------------------- ------------ --------------- ----------- ---------------- ------------------ Electric Gas All Adjustments/ Consolidated 1998 Operations Distribution Other Eliminations Total -------------------------------- ------------ --------------- ----------- ---------------- ------------------ External Customer Revenue $1,220 $230 $ 2 $(2) $1,450 Intersegment Revenue 201 3 - (204) - Operating Income (Loss) 423 29 - (4) 448 Interest Expense 4 n/a 4 86 94 Depreciation & Amortization 119 12 - - 131 Assets 4,305 381 4 (444) 4,246 Expenditures for Assets 186 19 - 48 253 Deferred Tax Assets 1 n/a - 20 21 -------------------------------- ------------ --------------- ----------- ---------------- ------------------ Management uses operating income to measure segment profitability for regulated operations. Accordingly, the Company does not allocate interest charges or income tax expense (benefit) to its segments. Similarly, management evaluates utility plant for its segments. Therefore, the Company does not allocate accumulated depreciation, common and non-utility plant, or deferred tax assets to reportable segments. Interest income is not reported by segment and is not material. The Consolidated Financial Statements report operating revenues which are comprised of the reportable segments. Revenues from non-reportable segments are included in Other Income. Therefore, the adjustments to total revenue remove revenues from non-reportable segments. Adjustments to assets consist of various reclassifications made for external reporting purposes. Segment assets include utility plant only (excluding accumulated depreciation) for all segments. As a result, unallocated assets include accumulated depreciation, offset in part by common and non-utility plant and non-fixed assets for the segments. Adjustments to Interest Expense and Deferred Tax Assets include primarily the totals from the Company that are not allocated to the segments. Interest Expense is also adjusted to eliminate inter-segment charges. Deferred Tax Assets are also adjusted to remove the non-current portion of those assets. 14. SUBSEQUENT EVENTS On January 24, 2001 the Company issued $150 million First Mortgage Bonds having an annual interest rate of 6.70 percent and maturing on February 1, 2001. 15. QUARTERLY FINANCIAL DATA (UNAUDITED) Millions of Dollars, except per share amounts ------------------------------------------------------- ----------- ------------- ------------ ------------ --------- First Second Third Fourth 2000 Quarter Quarter Quarter Quarter Annual ------------------------------------------------------- ----------- ------------- ------------ ------------ --------- Total operating revenues $395 $371 $448 $455 $1,669 Operating income 108(1) 96 155 98 457 Income before cumulative effect of accounting change 55 44 82 50 231 Cumulative effect of accounting change, net of taxes 22 - - - 22 Net income 77 44 82 50 253 ------------------------------------------------------- ----------- ------------- ------------ ------------ --------- ------------------------------------------------------- ----------- ------------- ------------ ------------ --------- First Second Third Fourth 1999 Quarter Quarter Quarter Quarter Annual ------------------------------------------------------- ----------- ------------- ------------ ------------ --------- Total operating revenues $352 $338 $431 $344 $1,465 Operating income 99 80 148 66 393 Net income 48 37 77 27 189 ------------------------------------------------------- ----------- ------------- ------------ ------------ --------- (1) Excludes $30 million of income taxes formerly reported in first quarter operating income. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED Item 7. Management's Narrative Analysis of Results of Operations................................. 109 Item 7A. Quantitative Disclosures About Market Risk................ 112 Item 8. Financial Statements and Supplementary Data............... 113 Public Service Company of North Carolina, Incorporated meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and therefore is filing this form with the reduced disclosure format allowed under General Instruction I(2). ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS. Statements included in this narrative analysis (or elsewhere in this annual report) which are not statements of historical fact are intended to be, and are hereby identified as, forward-looking statements for purposes of the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are cautioned that such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following: (1) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) changes in the utility regulatory environment, (3) changes in the economy, especially in PSNC's service territory, (4) the impact of competition from other energy suppliers, (5) growth opportunities, (6) the results of financing efforts, (7) changes in PSNC's accounting policies, (8) weather conditions, especially in areas served by PSNC, (9) inflation, (10) changes in environmental regulations, and (11) the other risks and uncertainties described from time to time in PSNC's periodic reports filed with the SEC. PSNC disclaims any obligation to update any forward-looking statements. SCANA acquired PSNC and PSNC's fiscal year was changed from September 30 to December 31, effective in 2000. The accompanying narrative analysis is presented in terms of a comparison of the twelve months ended December 31, 2000 and 1999. In connection with the acquisition, which was accounted for as a purchase, the excess of the purchase price over the fair value of PSNC's assets and liabilities was recorded as an acquisition adjustment which is being amortized over a 35 year period. Condensed Consolidated Income Statements ---------------------------------------------------- --------------------------------- ------------------ --------------- Twelve Months Ended December 31, % Millions of dollars 2000* 1999 Change Change ---------------------------------------------------- ----------------- --------------- ------------------ --------------- Operating Revenues $546.8 $306.7 $240.1 78.3 Cost of Gas (374.4) (141.5) (232.9) 164.6 ---------------------------------------------------- ----------------- --------------- ------------------ Gross Margin 172.4 165.2 7.2 4.4 ---------------------------------------------------- ----------------- --------------- ------------------ Operating Expenses: Operation and maintenance 67.6 69.3 (1.7) (2.5) Depreciation and amortization 41.9 26.2 15.7 59.9 Other taxes 6.4 12.9 (6.5) (50.4) ---------------------------------------------------- ----------------- --------------- ------------------ Total Operating Expenses 115.9 108.4 7.5 6.9 ---------------------------------------------------- ----------------- --------------- ------------------ Operating Income 56.5 56.8 (.3) (0.5) Other Income, net 8.2 6.6 1.6 24.2 Interest Charges 19.6 18.3 1.3 7.1 ---------------------------------------------------- ----------------- --------------- ------------------ Income Before Income Taxes and Cumulative Effect of Accounting Change 45.1 45.1 - - Income Taxes 23.9 19.3 4.6 23.8 ---------------------------------------------------- ----------------- --------------- ------------------ Income Before Cumulative Effect of Accounting Change 21.2 25.8 (4.6) (17.8) Cumulative Effect of Accounting Change, net of taxes 6.6 - 6.6 - ---------------------------------------------------- ----------------- --------------- ------------------ Net Income $27.8 $25.8 $2.0 7.8 ==================================================== ================= =============== ================== * Effective December 31, 1999, SCANA Public Service Company, L.L.C. (formerly Sonat Public Service Company, L. L.C.) was consolidated with PSNC. Earnings and Dividends Net income for the twelve months ended December 31, 2000 and 1999 was as follows: Millions of dollars 2000 1999 ----------------------------------------- ------------------ ----------------- Net income derived from: Continuing operations $21.2 $25.8 Cumulative effect of accounting change, net of taxes 6.6 - ========================================= ================== ================= Net income $27.8 $25.8 ========================================= ================== ================= Net income from continuing operations decreased approximately $4.6 million, primarily as a result of increased amortization expense arising from the amortization of the utility plant acquisition adjustment, which was partially offset by improved margin and a decrease in other taxes. In 2000 the cumulative effect of an accounting change resulted from the recording of unbilled revenues (See Note 2 of Notes to Consolidated Financial Statements). The nature of PSNC's business is seasonal. The quarters ending June 30 and September 30 are generally PSNC's least profitable quarters due to decreased demand for natural gas related to lower space heating requirements. PSNC's Board of Directors authorized payment of dividends on common stock held by SCANA as follows: Declaration Date Dividend Amount Quarter Ended Payment Date February 22, 2000 $6.0 million March 31, 2000 April 1, 2000 April 27, 2000 $5.0 million June 30, 2000 July 1, 2000 August 16, 2000 $4.5 million September 30, 2000 October 1, 2000 October 17, 2000 $3.5 million December 31, 2000 January 1, 2001 Gas Distribution Gas distribution sales margins (excluding the cumulative effect of the change in accounting and eliminating the impact of franchise taxes in 1999 as described at Other Operating Expenses) for the twelve months ended December 31, 2000 and 1999 were as follows: Millions of dollars 2000 1999 Change % Change ------------------------ ------------------------------------------------------ Gas operating revenue $405.6 $300.4 $105.2 35.0% Less: Cost of gas (237.4) (141.4) (96.0) 67.9% ======================== ===================================== Gross margin $168.2 $159.0 $9.2 5.8% ======================== ====================================================== The increase in margin for the year ended December 31, 2000 primarily resulted from customer growth. Energy Marketing Energy marketing is comprised of SCANA Public Service Company, L.L.C., which became a wholly owned subsidiary of PSNC effective December 31, 1999 and participates in nonregulated activities such as natural gas brokering and supply services. Energy marketing operating revenues and net income (including affiliated transactions) for the year ended December 31, 2000 was as follows: Millions of dollars ----------------------------------------------------------------------- Operating revenues $142.9 Net income 2.0 ======================================================================= Operation and Maintenance Expenses The $1.7 million decrease in operation and maintenance expenses from 1999 reflects a net decrease in operating costs arising from the acquisition of PSNC by SCANA (see Note 3 of Notes to Consolidated Financial Statements). This decrease was partially offset by the consolidation of SCANA Public Service Company, L.L.C. in 2000. Other Operating Expenses Depreciation and amortization expense increased approximately $15.7 million for the year ended December 31, 2000 as compared to the same period in 1999 primarily due to the amortization of the utility plant acquisition adjustment (see Note 3 of Notes to Consolidated Financial Statements). Other taxes decreased for the year ended December 31, 2000 as compared to the same period in 1999 primarily as a result of the elimination of franchise taxes by the State of North Carolina effective August 1, 1999. The franchise tax was replaced by an excise tax. Franchise taxes totaled $6.3 million in 1999, and were included in PSNC's billing rates and recorded as both operating revenues and other taxes. The new excise tax is added to customer bills based on the volume of natural gas consumed. PSNC does not include the excise tax in either operating revenues or other taxes , as this tax is a pass-through from the customer to the State of North Carolina. Other Income, net Other income increased for the year ended December 31, 2000 as compared to the same period in 1999 primarily due to a $1.4 million gain on the sale of properties during the fourth quarter 2000 and an increase in income from subsidiary operations. Interest Expense Interest expense increased $1.3 million over 1999 as a result of increased borrowings and increased weighted average interest rates on short-term debt. Income Taxes Income taxes increased for the year ended December 31, 2000 compared to the corresponding period for 1999, primarily due to the non-deductibility of amortization expense related to the acquisition adjustment. Capital Expansion Program PSNC's capital expansion program includes the construction of lines, systems and facilities and the purchase of related equipment. PSNC's 2001 construction budget is approximately $58 million, compared to actual construction expenditures for 2000 of $39.1 million. The financing of the capital expansion program is expected to be funded through borrowings, including advances from SCANA. Competition Although PSNC is the sole distributor of natural gas in its service area, it faces competition from suppliers of alternate fuels. The primary alternate fuels available to large commercial and industrial customers are fuel oil and propane. The primary competition to natural gas in the residential and smaller commercial markets is electricity. The NCUC has approved a rate structure that allows PSNC to negotiate reduced rates in order to match the cost of alternate fuels to large commercial and industrial customers and recover the lost margin from other classes of customers. PSNC anticipates that the need to negotiate reduced rates with these customers will continue. Electric restructuring efforts in North Carolina have been stalled by developments in California, concerns over municipal power agencies' debt and other factors. Legislation or regulatory action at the Federal level, particularly as part of a larger energy policy initiative, may be considered in 2001. PSNC is not able to predict whether any restructuring legislation or regulatory action will be enacted and, if it is, the impact it will have on PSNC and the natural gas industry. Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK All financial instruments held by PSNC described below are held for purposes other than trading. Interest rate risk - The table below provides information about PSNC's financial instruments that are sensitive to changes in interest rates. For debt obligations, the table presents principal cash flows and related weighted average interest rates by expected maturity dates. December 31, 2000 Expected Maturity Date (Millions of dollars) Fair Liabilities 2001 2002 2003 2004 2005 Thereafter Total Value -------------------------------- --------- ---------- ---------- ---------- ---------- ----------- ---------- ---------- Long-Term Debt: Fixed Rate ($) 4.3 4.3 7.5 7.5 3.2 122.4 149.2 154.9 Average Fixed Interest Rate 10.0% 10.0% 9.47% 9.47% 8.75% 7.50% 7.87% - December 31, 1999 Expected Maturity Date (Millions of dollars) Fair Liabilities 2000 2001 2002 2003 2004 Thereafter Total Value -------------------------------- --------- --------- --------- ---------- ----------- ----------- ----------- ---------- Long-Term Debt: Fixed Rate ($) 6.8 5.6 4.3 7.5 7.5 125.6 157.3 156.4 Average Fixed Interest Rate 10.0% 10.0% 10.0% 9.47% 9.47% 7.53% 7.98% - While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Page Independent Auditors' Reports........................................ 114 Consolidated Financial Statements: Consolidated Balance Sheets as of December 31, 2000 and 1999.......... 116 Consolidated Statements of Income and Retained Earnings for the Year Ended December 31, 2000, the Three Months Ended December 31, 1999 and the Fiscal Years Ended September 30, 1999 and 1998.................................... 117 Consolidated Statements of Cash Flows for the Year Ended December 31, 2000, the Three Months Ended December 31, 1999 and the Fiscal Years Ended September 30, 1999 and 1998.............. 118 Consolidated Statements of Capitalization as of December 31, 2000 and 1999........................................... 119 Notes to Consolidated Financial Statements............................. 120 INDEPENDENT AUDITORS' REPORT Public Service Company of North Carolina, Incorporated: We have audited the accompanying Consolidated Balance Sheets and Statements of Capitalization of Public Service Company of North Carolina, Incorporated (Company) as of December 31, 2000 and 1999, and the related Consolidated Statements of Income and Retained Earnings and of Cash Flows for the year ended December 31, 2000 and for the three months ended December 31, 1999. Our audits also included the financial statement schedule listed in Part IV at Item 14. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits. The consolidated financial statements of the Company for the fiscal years ended September 30, 1999 and 1998 were audited by other auditors whose report, dated November 4, 1999 (except with respect to matters discussed in Note 13, as to which the date is December 17, 1999), expressed an unqualified opinion on those statements. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 2000 and 1999 consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2000 and 1999, and the results of its operations and its cash flows for the year ended December 31, 2000 and for the three months ended December 31, 1999 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. As discussed in Notes 1D and 2, respectively, to the consolidated financial statements, effective January 1, 2000, the Company changed its fiscal year end to December 31 and its method of accounting for operating revenues associated with its regulated utility operations. s/DELOITTE & TOUCHE LLP DELOITTE & TOUCHE LLP Columbia, South Carolina February 7, 2001 (February 16, 2001 as to Note 15) REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS We have audited in accordance with generally accepted auditing standards, the consolidated financial statements of Public Service Company of North Carolina, Incorporated included in this Form 10-K, and have issued our report thereon dated November 4, 1999 (except with respect to the matters discussed in Note 13, as to which the date is December 17, 1999). Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed in the index are the responsibility of the Registrant's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. s/Arthur Andersen LLP Charlotte, North Carolina November 4, 1999 PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONSOLIDATED BALANCE SHEETS -------------------------------------------------------------------------- ------------------------ -------------------------- Successor Predecessor December 31, December 31, Millions of dollars 2000 1999 -------------------------------------------------------------------------- ------------------------ -------------------------- Assets Gas Utility Plant (Note 1) $787 $768 Less - Accumulated depreciation 263 245 Acquisition Adjustment, net of accumulated amortization (Notes 1 & 3) 452 - -------------------------------------------------------------------------- ------------------------ -------------------------- Gas Utility Plant, Net 976 523 -------------------------------------------------------------------------- ------------------------ -------------------------- Nonutility Property and Investments, net of accumulated depreciation 34 31 -------------------------------------------------------------------------- ------------------------ -------------------------- Current Assets: Cash and temporary investments (Note 1) 7 9 Restricted cash and temporary investments (Note 1) 5 3 Receivables (net of provisions for uncollectible accounts of $2.4 million for 2000 and $2.7 million for 1999) 149 59 Inventories (at average cost): Stored gas 32 29 Materials and supplies 7 7 Deferred gas costs, net (Note 2) 9 27 Other 1 1 -------------------------------------------------------------------------- ------------------------ -------------------------- Total Current Assets 210 135 -------------------------------------------------------------------------- ------------------------ -------------------------- Deferred Charges and Other Assets: Due from affiliate-pension asset (Note 6) 10 - Other 18 9 -------------------------------------------------------------------------- ------------------------ -------------------------- Total Deferred Charges and Other Assets 28 9 -------------------------------------------------------------------------- ------------------------ -------------------------- Total $1,248 $698 ========================================================================== ------------------------ ========================== ========================================================================== ------------------------ ========================== Capitalization and Liabilities Capitalization: Common equity (Note 9) $712 $232 Long-term debt, net (Notes 7 & 11) 145 151 -------------------------------------------------------------------------- ------------------------ -------------------------- Total Capitalization 857 383 -------------------------------------------------------------------------- ------------------------ -------------------------- Current Liabilities: Short-term borrowings (Notes 8 & 11) 125 138 Current portion of long-term debt (Note 7) 4 7 Accounts payable 84 50 Accrued taxes 3 5 Customer prepayments and deposits 8 7 Advances from parent 44 - Dividends declared and interest accrued 5 8 Other 6 2 -------------------------------------------------------------------------- ------------------------ -------------------------- Total Current Liabilities 279 217 -------------------------------------------------------------------------- ------------------------ -------------------------- Deferred Credits and Other Liabilities: Deferred income taxes, net (Notes 1 & 10) 82 75 Deferred investment tax credits (Notes 1 & 10) 3 3 Accrued pension cost (Note 6) - 3 Due to affiliate-postretirement benefits (Note 6) 10 - Other 17 17 -------------------------------------------------------------------------- ------------------------ -------------------------- Total Deferred Credits and Other Liabilities 112 98 -------------------------------------------------------------------------- ------------------------ -------------------------- Total $1,248 $698 ========================================================================== ------------------------ ========================== See Notes to Consolidated Financial Statements. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS ----------------------------------------------------------- --------------- ----------------------------------------------------- Successor Predecessor ----------------------------------------------------------- --------------- ----------------- ----------------------------------- Year Three Months Ended Ended Fiscal Year Ended December 31, December 31, September 30, September 30, Millions of dollars 2000 1999 1999 1998 ----------------------------------------------------------- --------------- ----------------- ----------------- ----------------- Operating Revenues $547 $81 $298 $330 Cost of Gas 375 41 133 174 ----------------------------------------------------------- --------------- ----------------- ----------------- ----------------- Gross Margin 172 40 165 156 ----------------------------------------------------------- --------------- ----------------- ----------------- ----------------- Operating Expenses: Operation and maintenance 67 18 71 60 Depreciation and amortization 42 7 26 25 Other taxes 6 2 15 17 ----------------------------------------------------------- --------------- ----------------- ----------------- ----------------- Total Operating Expenses 115 27 112 102 ----------------------------------------------------------- --------------- ----------------- ----------------- ----------------- Operating Income 57 13 53 54 Other Income, net 8 1 6 5 Interest Charges 20 5 18 18 ----------------------------------------------------------- --------------- ----------------- ----------------- ----------------- Income Before Income Taxes and Cumulative Effect of Accounting Change 45 9 41 41 Income Taxes 24 4 17 16 ----------------------------------------------------------- --------------- ----------------- ----------------- ----------------- Income Before Cumulative Effect of Accounting Change 21 5 24 25 Cumulative Effect of Accounting Change, net of taxes (Note 2) 7 - - - ----------------------------------------------------------- --------------- ----------------- ----------------- ----------------- ----------------------------------------------------------- --------------- ----------------- ----------------- ----------------- Net Income 28 5 24 25 Retained Earnings at Beginning of Period 73 73 70 64 Acquisition of Company (73) - - - Common Stock Cash Dividends Declared (19) (5) (21) (19) ----------------------------------------------------------- --------------- ----------------- ----------------- ----------------- =========================================================== =============== ================= ================= ================= Retained Earnings at End of Period $9 $73 $73 $70 =========================================================== =============== ================= ================= ================= See Notes to Consolidated Financial Statements. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONSOLIDATED STATEMENTS OF CASH FLOWS --------------------------------------------------------- ----------------- ----------------------------------------------------- Successor Predecessor --------------------------------------------------------- ----------------- ------------------ ---------------------------------- Year Three Months Ended Ended Fiscal Year Ended December 31, December 31, September 30, September 30, Millions of dollars 2000 1999 1999 1998 --------------------------------------------------------- ----------------- ------------------ ---------------- ----------------- Cash Flows From Operating Activities: Net income $28 $5 $24 $25 Adjustments to reconcile net income to net cash provided from (used in) operating activities: Cumulative effect of accounting change, net of taxes (7) - - - Depreciation and amortization 47 8 29 28 Over (under) collections, fuel adjustment clause 9 - 5 (6) Change in operating assets and liabilities: (Increase) decrease in receivables, net (77) (49) (9) 11 (Increase) decrease in inventories (3) - (5) (3) (Increase) decrease in deferred gas cost 5 (8) (5) 6 Increase (decrease) in accounts payable and advances 78 39 5 (7) Increase (decrease) in accrued pension cost - (1) (3) (2) Increase (decrease) in postretirement payable 1 - - - Increase (decrease) in deferred income taxes, net 9 - 8 7 Other, net (14) - 1 (5) --------------------------------------------------------- ----------------- ------------------ ---------------- ----------------- Net Cash Provided From (Used In) Operating Activities 76 (6) 50 54 --------------------------------------------------------- ----------------- ---------------- ----------------- ------------------ Cash Flows From Investing Activities: Construction expenditures (39) (12) (44) (65) Sales of assets 5 - - - Nonutility and other (1) (1) (5) (2) --------------------------------------------------------- ----------------- ------------------ ---------------- ----------------- Net Cash Provided From (Used For) Investing Activities (35) (13) (49) (67) --------------------------------------------------------- ----------------- ------------------ ---------------- ----------------- Cash Flows From Financing Activities: Issuance of common stock - - 6 10 Increase (decrease) in short-term borrowings, net (13) 34 34 33 Retirement of long-term debt and common stock (9) (8) (17) (10) Cash dividends (21) (5) (20) (19) --------------------------------------------------------- ----------------- ------------------ ---------------- ----------------- Net Cash Provided From (Used For) Financing Activities (43) 21 3 14 --------------------------------------------------------- ----------------- ------------------ ---------------- ----------------- Net (Decrease) Increase in Cash and Temporary Investments (2) 2 4 1 Cash and Temporary Investments at Beginning of Period 9 7 3 2 --------------------------------------------------------- ----------------- ------------------ ---------------- ----------------- --------------------------------------------------------- ----------------- ------------------ ---------------- ----------------- Cash and Temporary Investments at End of Period $7 $9 $7 $3 ========================================================= ================= ================== ================ ================= Supplemental Cash Flow Information: Cash paid during the period for: Interest (net of capitalized interest of $1.0, $0.1, $0.6 and $0.6) $21 $5 $18 $18 Income taxes 25 - 7 12 In connection with the acquisition of Public Service Company of North Carolina, Inc. by SCANA Corporation, $21 million in common stock was cancelled. The application of push-down accounting for the acquisition resulted in the recording of a $466 million acquisition adjustment. See Notes to Consolidated Financial Statements. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONSOLIDATED STATEMENTS OF CAPITALIZATION -------------------------------------------------------------------------- ---------------- ---------------- Successor Predecessor -------------------------------------------------------------------------- ---------------- ---------------- December 31, (Millions of dollars) 2000 1999 -------------------------------------------------------------------------- ---------------- ---------------- Common Equity: Common stock, $1 par, 1,000 shares authorized and issued in 2000; 30,000,000 shares authorized, 20,577,967 shares issued in 1999 $- $21 Capital in excess of par value 703 138 Retained earnings 9 73 -------------------------------------------------------------------------- ---------------- ---------------- Total Common Equity 712 232 -------------------------------------------------------------------------- ---------------- ---------------- Long-term Debt: Senior debentures (unsecured) - 10% due 2003 - 4 10% due 2004 17 22 8.75% due 2012 32 32 6.99% due 2026 50 50 7.45% due 2026 50 50 -------------------------------------------------------------------------- ---------------- ---------------- 149 158 Less - Current maturities (4) (7) -------------------------------------------------------------------------- ---------------- ---------------- Total Long-Term Debt, Net 145 151 -------------------------------------------------------------------------- ---------------- ---------------- ========================================================================== ================ ================ Total Capitalization $857 $383 ========================================================================== ================ ================ See Notes to Consolidated Financial Statements. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. Organization and Principles of Consolidation Public Service Company of North Carolina, Incorporated (PSNC), a public utility, was organized as a North Carolina corporation in 1938. Effective January 1, 2000 the acquisition of PSNC by SCANA Corporation (SCANA), a South Carolina holding company, was consummated in a business combination accounted for as a purchase. As a result, PSNC became a wholly owned subsidiary of SCANA incorporated under the laws of South Carolina. PSNC is engaged predominantly in the transportation, distribution and sale of natural gas to residential, commercial and industrial customers in North Carolina. The accompanying Consolidated Financial Statements include the accounts of PSNC and its subsidiary companies, PSNC Production Corporation, SCANA Public Service Company, L.L.C. (formerly Sonat Public Service Company, L.L.C.), Clean Energy Enterprises, Inc., PSNC Blue Ridge Corporation, and PSNC Cardinal Pipeline Company (collectively, the "Company"). The accounts of SCANA Public Service Company, L.L.C. are included only for the period subsequent to their acquisition (See Note 4). Investments in other affiliates in which the Company has the ability to exercise influence over operating and financial policies are accounted for under the equity method. Significant intercompany balances and transactions have been eliminated in consolidation. Affiliated Transactions At December 31, 2000 PSNC had recorded $4.3 million in associated company receivables and $1.7 million in associated company payables with various SCANA subsidiaries. These amounts are included in PSNC's accounts receivable and accounts payable, respectively. B. Basis of Accounting PSNC accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71. This accounting standard requires cost-based rate-regulated utilities to recognize in their financial statements revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, PSNC has recorded, as of December 31, 2000, approximately $21.0 million and $4.6 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax liabilities of approximately $0.4 million. The regulatory assets are recoverable through rates. In the future, as a result of deregulation or other changes in the regulatory environment, PSNC may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on PSNC's results of operations in the period the write-off would be recorded, but it is not expected that cash flows or financial position would be materially affected. C. System of Accounts The accounting records of PSNC are maintained in accordance with the Uniform System of Accounts prescribed by the National Association of Regulatory Utility Commissioners (NARUC) and as adopted by the North Carolina Utilities Commission (NCUC). D. Change in Fiscal Year PSNC changed its fiscal year end to December 31 from September 30, effective January 1, 2000. E. 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. F. Allowance for Funds Used During Construction (AFC) AFC, a noncash item, reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the cost of debt 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 calculated AFC composite rates were 6.8 percent for the year ended 2000, 6.4 percent for the three months ended December 31, 1999 and 5.5 percent and 5.9 percent for the fiscal years ended 1999 and 1998, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. G. Revenue Recognition Revenues are recorded during the accounting period in which services are provided to customers, and include estimated amounts for natural gas delivered, but not yet billed. Prior to January 1, 2000 revenues related to regulated gas services were recorded only as customers were billed. (See Note 2.) PSNC's Rider D mechanism authorizes the recovery of all prudently incurred gas costs from customers on a monthly basis. Any difference in amounts paid and collected for these costs is deferred for subsequent refund to or collection from customers. Additionally, PSNC can recover its margin losses on negotiated gas sales to certain large commercial/industrial customers in any manner authorized by the NCUC. At December 31, 2000 and 1999 PSNC had undercollected from customers pursuant to Rider D approximately $9.3 million and $16.7 million, respectively, which is in "Deferred Gas Costs, net." PSNC's gas rate schedules for residential, small commercial and small industrial customers include a weather normalization adjustment, which minimizes fluctuations in gas revenues due to abnormal weather conditions. PSNC establishes its commodity cost of gas for large commercial and industrial customers on the basis of market prices for natural gas as approved by the NCUC. H. Depreciation and Amortization Provisions for depreciation and amortization are recorded using the straight-line method and are based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates approximate 4.1 percent for the year ended December 31, 2000, 4.1 percent for the three months ended December 31, 1999 and 3.9 percent and 4.0 percent for the fiscal years ended September 30, 1999 and 1998. The acquisition adjustment related to the acquisition of PSNC by SCANA is being amortized over a 35-year period using the straight-line method. I. Income Taxes In 2000 PSNC is included in the consolidated federal income tax return of SCANA Corporation. Under a joint consolidated income tax allocation agreement each subsidiary's current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted rates. Deferred tax assets and liabilities are adjusted for changes in such rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers; otherwise they are charged or credited to income tax expense. J. Debt Expense PSNC amortizes issuance costs for its debentures over the life of the related debt. PSNC is amortizing the redemption premium and the unamortized issuance costs on its previously refunded Series K First Mortgage Bonds over 15 years (1987-2002), in accordance with the treatment authorized by the NCUC. K. Environmental PSNC maintains an environmental assessment program to identify and assess current and former operation sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the expenditures, if any, deemed necessary to investigate and remediate 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 to regulated operations. Such amounts are deferred and amortized with recovery provided through rates. L. Cash and Temporary Investments PSNC considers temporary cash investments having original maturities of three months or less to be cash equivalents. Temporary cash investments may include repurchase agreements, U.S. Treasury bills, federal agency securities, certificates of deposit and high-grade commercial paper. Since fiscal 1992, PSNC has received refunds from its pipeline transporters for which the investment and use have been restricted by an order of the NCUC. Pursuant to an order of the NCUC, these funds are segregated from PSNC's general funds and will be used for expansion of PSNC's facilities into unserved territories. These refunds, along with interest earned thereon, are periodically transferred to the Office of the State Treasurer of North Carolina. The balance not transferred is reported in restricted cash and temporary investments. At December 31, 2000 the balance in restricted cash and temporary investments includes approximately $4.5 million in supplier refunds to be returned to customers in the form of a bill credit during the first quarter of 2001. This refund to customers was approved by the NCUC to help defray the unusually high cost of natural gas experienced during the most recent heating season. M. Recently Issued Accounting Standard and Bulletin In June 1998 the Financial Accounting Standards Board (FASB) issued SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." In June 2000 the FASB issued SFAS 138, which amends certain provisions of SFAS 133 to expand the normal purchase and sale exemption for supply contracts and to redefine interest rate risk to reduce sources of ineffectiveness, among other things. PSNC's adoption of SFAS 133, as amended, on January 1, 2001 did not have a material impact on PSNC's results of operations, cash flows or financial position. In December 1999 Staff Accounting Bulletin No. 101, "Revenue Recognition in Financial Statements" was issued by the Securities and Exchange Commission (SEC), and provides the SEC staff's views in applying generally accepted accounting principles to selected revenue recognition issues. PSNC's adoption of this bulletin in the fourth quarter of 2000 had no impact on its results of operations, cash flows or financial position. N. Reclassifications Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2000. O. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 2. CUMULATIVE EFFECT OF ACCOUNTING CHANGE Effective January 1, 2000 PSNC changed its method of accounting for operating revenues associated with its regulated utility operations from cycle billing to full accrual. The cumulative effect of this change was approximately $6.6 million, net of taxes. Accruing unbilled revenues more closely matches revenues and expenses. Unbilled revenues represent the estimated amount customers will be charged for service rendered but not yet billed as of the end of the accounting period. At December 31, 1999 the gas costs associated with unbilled revenues were deferred. Beginning January 1, 2000 these costs are no longer deferred. If this method had been applied retroactively, net income would have been $11.0 million for the three months ended December 31, 1999, compared to $5.1 million , as previously reported. Further, if this method had been applied retroactively to the fiscal years ended September 30 1999 and 1998, the impact on net income would not have been material. 3. ACQUISITION BY SCANA CORPORATION On February 10, 2000 the acquisition of PSNC by SCANA was consummated in a business combination accounted for as a purchase. PSNC became a wholly owned subsidiary of SCANA effective January 1, 2000. Pursuant to the Agreement and Plan of Merger, PSNC shareholders were paid approximately $212 million in cash and 17.4 million shares of SCANA common stock valued at approximately $488 million. PSNC has recorded a utility plant acquisition adjustment of approximately $466 million, which reflects the excess of SCANA's purchase price over the fair value of PSNC's net assets at January 1, 2000. The adjustment is being amortized over 35 years on the straight-line basis. Common equity at December 31, 2000 includes the effect of the acquisition adjustment. PSNC agreed to pay approximately $5 million to ten key executives under severance agreements related to the acquisition. Severance benefits of approximately $2.7 million have been paid to seven key executives whose positions were eliminated. In addition, approximately $3.1 million was paid to former directors of PSNC in connection with deferred compensation and retirement plans, and approximately $8.1 million was paid to participants in PSNC's nonqualified stock option plans. 4. ACQUISITION OF SONAT PUBLIC SERVICE COMPANY Effective December 31, 1999 PSNC Production Corporation (PSNC Production), a wholly owned subsidiary of PSNC, purchased the remaining 50% membership interest in Sonat Public Service Company, L.L.C. (Sonat). As a result, Sonat became a wholly owned subsidiary of PSNC Production. PSNC Production paid $5.3 million to acquire this interest. Sonat was subsequently renamed SCANA Public Service Company, L.L.C. (SCANA Public Service). 5. RATE AND OTHER REGULATORY MATTERS A. On April 6, 2000 the NCUC issued an order permanently approving PSNC's request to establish its commodity cost of gas for large commercial and industrial customers on the basis of market prices for natural gas. The NCUC previously allowed PSNC use of this mechanism on a trial basis. This procedure ensures that the amount paid by PSNC for natural gas to serve these customers approximates the amount collected from them. B. A state expansion fund, established by the North Carolina General Assembly in 1991 and funded by refunds from PSNC's interstate pipeline transporters, provides financing for expansion into areas that otherwise would not be economically feasible to serve. On December 30, 1999 PSNC filed an application with the NCUC to extend natural gas service to Madison, Jackson and Swain Counties. Pursuant to state statutes, the NCUC required PSNC to forfeit its exclusive franchises to serve six counties in western North Carolina effective January 31, 2000 because these counties were not receiving any natural gas service. Madison, Jackson and Swain Counties were included in the forfeiture order. On June 29, 2000 the NCUC approved PSNC's requests for reinstatement of its exclusive franchises for Madison, Jackson and Swain Counties and disbursement of up to $28.4 million from PSNC's expansion fund for this project. PSNC estimates that the cost of this project will be approximately $31.4 million. C. On December 7, 1999 the NCUC issued an order approving the acquisition of PSNC by SCANA. As specified in the NCUC order, PSNC reduced its rates by approximately $1 million in August 2000, will reduce rates another $1 million in August 2001 and has agreed to a five-year moratorium on general rate cases. General rate relief can be obtained during this period to recover costs associated with materially adverse governmental actions and force majeure events. D. On February 22, 1999 the NCUC approved PSNC's application to use expansion funds to extend natural gas service into Alexander County, and authorized disbursements from the fund of approximately $4.3 million based upon budgeted construction cost of approximately $6.2 million. Most of Alexander County lies within PSNC's certificated service territory and did not previously have natural gas service. The project was completed and customers began receiving natural gas service in March 2000. E. On October 30, 1998 the NCUC issued an order in PSNC's general rate case filed in April 1998. The order, effective November 1, 1998, granted PSNC additional revenue of $12.4 million and allowed a 9.82 percent overall rate of return on PSNC's net utility investment. It also approved the continuation of the Weather Normalization Adjustment (WNA) and Rider D mechanisms and full margin transportation rates. PSNC's Rider D rate mechanism authorizes the recovery of all prudently incurred gas costs from customers on a monthly basis. Any difference in amounts paid and collected for these costs is deferred for subsequent refund to or collection from customers. On February 4, 2000 in response to an appeal by the Carolina Utility Customers Association, Inc., the Supreme Court of North Carolina affirmed the NCUC order. 6. EMPLOYEE BENEFIT PLANS AND STOCK COMPENSATION PLANS Employee Benefit Plans Since July 1, 2000 PSNC has participated in SCANA's noncontributory defined benefit pension plan, which covers substantially all permanent employees. SCANA's pension plan benefits for PSNC employees are calculated using a cash balance formula under which employees earn benefits through monthly compensation and interest credits. SCANA's policy has been to fund the plan to the extent permitted by the applicable Federal income tax regulations as determined by an independent actuary. Also, since July 1, 2000 PSNC has participated in SCANA's plan to provide certain unfunded health care and life insurance benefits to active and retired employees. Retirees share in a portion of their medical care cost and are provided life insurance benefits at no charge. The cost 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 July 1, 2000 PSNC and its subsidiaries sponsored a noncontributory defined benefit pension plan covering substantially all employees. The benefits were based on years of service and the employee's compensation during the five consecutive years of employment that produced the highest average pay. Contributions to the plan were determined on an annual basis, with the amount of such contributions being within the range of the minimum required funding amount and the maximum amount deductible for Federal income tax purposes. Prior to July 1, 2000 PSNC also provided certain health care and life insurance benefits to its employees. Retirees were required to contribute toward the costs of their medical care coverage. The costs of postretirement benefits other than pensions were accrued during the years the employees rendered the service necessary to be eligible for the applicable benefits. During the fiscal year ended September 30, 1999, PSNC recognized pension gains of $1.8 million and a net curtailment loss on postretirement benefit obligations of $0.5 million directly related to severance activity under restructuring discussed further in Note 13. The fair value of PSNC's common stock held by its plan at June 30, 2000, December 31, 1999, and September 30, 1999 measurement dates were approximately $0.0 million, $1.4 million and $1.3, million respectively. As discussed above, effective July 1, 2000, PSNC's pension and postretirement plans were merged with SCANA's plans. At the time of the plan mergers, PSNC had recognized a prepaid pension cost of approximately $9.0 million and a postretirement welfare plan obligation of approximately $9.1 million. For the period July 1 through December 31, 2000, PSNC's net periodic benefit income was approximately $0.6 million income for the pension plan and PSNC's net periodic benefit cost was approximately $0.7 million cost for the postretirement plan. Disclosures required for these PSNC's plans under SFAS 132 "Employer's Disclosures about Pensions and Other Postretirement Benefits" for the periods prior to the plan mergers are set forth in the following tables: Components of Net Periodic Benefit Cost Retirement Benefits Six Months Three Months Ended Ended Year Ended Year Ended June 30, December 31, September 30, September 30, Millions of dollars 2000 1999 1999 1998 ------------------------------------ -------------------- --------------------- ---------------------- ----------------------- Service cost $0.8 $0.5 $2.3 $2.1 Interest cost 1.6 0.8 3.0 3.0 Expected return on plan assets (2.2) (0.8) (3.1) (2.7) Prior service cost amortization - 0.1 0.6 0.6 Transition amount amortization - (0.1) (0.3) (0.3) ==================================== ==================== ===================== ====================== ======================= Net periodic benefit cost $0.2 $0.5 $2.5 $2.7 ==================================== ==================== ===================== ====================== ======================= Other Postretirement Benefits Six Months Three Months Ended Ended Year Ended Year Ended June 30, December 31, September 30, September 30, Millions of dollars 2000 1999 1999 1998 ------------------------------------ -------------------- --------------------- ---------------------- ----------------------- Service cost $0.1 $0.1 $0.3 $0.3 Interest cost 0.4 0.2 0.6 0.6 Prior service cost amortization - - 0.1 - Transition amount amortization - - 0.2 0.2 ==================================== ==================== ===================== ====================== ======================= Net periodic benefit cost $0.5 $0.3 $1.2 $1.1 ==================================== ==================== ===================== ====================== ======================= Weighted-Average Assumptions Retirement Benefits Six Months Three Months Ended Ended Year Ended Year Ended June 30, December 31, September 30, September 30, 2000 1999 1999 1998 ------------------------------------ -------------------- --------------------- ---------------------- --------------------- Discount rate 8.00% 8.00% 7.50% 6.75% Expected return on plan assets 9.50% 9.50% 8.00% 8.00% Rate of compensation increase Age-related Age-related Age-related Age-related Other Postretirement Benefits Six Months Three Months Ended Ended Year Ended Year Ended June 30, December 31, September 30, September 30, 2000 1999 1999 1998 ------------------------------------ -------------------- -------------------- ----------------------- ----------------------- Discount rate 8.00% 8.00% 7.50% 6.75% Expected return on plan assets n/a n/a n/a n/a Rate of compensation increase Age-related Age-related Age-related Age-related Changes in Benefit Obligations Retirement Benefits Six Months Three Months Ended Ended Year Ended June 30, December 31, September 30, Millions of dollars 2000 1999 1999 --------------------------------------------------- -------------------- --------------------- ------------------------ Benefit obligation, beginning of period $38.7 $44.1 $46.6 Service cost 0.8 0.5 2.3 Interest cost 1.6 0.8 3.0 Settlement payments - - (7.2) Benefits paid (2.5) (2.2) (0.5) Curtailment gain - - (1.2) Actuarial (gain) loss 1.3 (4.5) 1.1 --------------------------------------------------- -------------------- --------------------- ------------------------ Benefit obligation at end of period $39.9 $38.7 $44.1 =================================================== ==================== ===================== ======================== Other Postretirement Benefits Six Months Three Months Ended Ended Year Ended June 30, December 31, September 30, Millions of dollars 2000 1999 1999 --------------------------------------------------- --------------------- -------------------- ------------------------ Benefit obligation, beginning of period $8.9 $9.3 $9.0 Service cost 0.1 - 0.3 Interest cost 0.4 0.2 0.6 Benefits paid (0.3) (0.1) (0.6) Curtailment gain - - (0.3) Actuarial (gain) loss 2.1 (0.5) 0.3 --------------------------------------------------- --------------------- -------------------- ------------------------ Benefit obligation at end of period $11.2 $8.9 $9.3 =================================================== ===================== ==================== ======================== Change in Plan Assets Retirement Benefits Six Months Three Months Ended Ended Year Ended June 30, December 31, September 30, Millions of dollars 2000 1999 1999 --------------------------------------------------- --------------------- -------------------- ------------------------ Fair value of plan assets, beginning of period $47.9 $45.0 $43.7 Actual return on plan assets 0.8 3.1 5.3 Company contribution - 2.0 3.7 Benefits paid (2.5) (2.2) (7.7) --------------------------------------------------- -------------------- --------------------- ------------------------ Fair value of plan assets at end of period $46.2 $47.9 $45.0 =================================================== ==================== ===================== ======================== Funded Status of Plans Retirement Benefits Six Months Three Months Ended Ended Year Ended June 30, December 31, September 30, Millions of dollars 2000 1999 1999 --------------------------------------------------- -------------------- --------------------- ------------------------ Funded status, beginning of period $6.3 $9.2 $0.9 Unrecognized actuarial (gain) loss 2.7 (14.4) (7.6) Unrecognized prior service cost - 2.5 2.7 Unrecognized net transition obligation - (0.8) (1.0) --------------------------------------------------- -------------------- --------------------- ------------------------ Net asset (liability) recognized in Consolidated Balance Sheet $9.0 $(3.5) $(5.0) =================================================== ==================== ===================== ======================== Other Postretirement Benefits Six Months Three Months Ended Ended Year Ended June 30, December 31, September 30, Millions of dollars 2000 1999 1999 ------------------------------------------------- --------------------- ------------------- --------------------------- Funded status, beginning of period $(11.2) $(8.9) $(9.3) Unrecognized actuarial (gain) loss 2.1 (0.5) 0.3 Unrecognized prior service cost - 0.4 0.4 Unrecognized transition obligation - 2.7 2.8 ------------------------------------------------- -------------------- --------------------- -------------------------- Net asset (liability) recognized in Consolidated Balance Sheet $(9.1) $(6.3) $(5.8) ================================================= ==================== ===================== ========================== Health Care Trends The determination of net periodic other postretirement benefit cost is based on the following assumptions: Six Months Three Months Ended Ended Year Ended June 30, December 31, September 30, 2000 1999 1999 ------------------------------------------------- --------------------- ------------------- --------------------------- Health care cost trend rate 8.00% 8.00% 7.75% Ultimate health care cost trend rate 5.50% 5.50% 4.25% Year achieved 2005 2005 2008 Stock Compensation Plans Prior to SCANA's acquisition of PSNC effective January 1, 2000, PSNC sponsored the stock-based compensation plans described below. PSNC applied the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" and related interpretations in accounting for grants made under the plans. Because all options granted after September 30, 1997 were granted with exercise prices equal to the fair market value of the Company's stock on the respective grant dates, no compensation expense was recognized in connection with such grants. If PSNC had determined compensation expense for the issuance of options based on the fair value method described in SFAS 123, "Accounting for Stock-Based Compensation," net income would have been reduced to the pro forma amounts shown below: Year Ended September 30, Millions of dollars 1999 1998 --------------------- -------------------------------------------- Net income As reported $24.5 $24.8 Pro forma $23.7 $23.6 Nonqualified Stock Option Plans PSNC sponsored a 1992 Nonqualified Stock Option Plan (1992 Plan) and a 1997 Nonqualified Stock Option Plan (1997 Plan). In accordance with the 1992 Plan, options to purchase PSNC common stock could have been granted to officers and key employees of PSNC at 90 percent of the fair market value of the stock determined on the date of the grant. Under the 1997 Plan, options to purchase PSNC's common stock could have been granted to officers and key employees of PSNC at the fair market value of the stock determined on the date of the grant. Options from the 1992 Plan and the 1997 Plan were exercisable beginning two years from the date of the grant and expired five years from the date of the grant. In addition, upon a change in control event, which occurred with shareholder approval of PSNC's acquisition by SCANA, all outstanding options became exercisable on July 1, 1999. Options granted, exercised and canceled under both plans for the periods indicated were as follows: Options Weighted-Average Outstanding Exercise Price --------------------------------------------------- -------------------------- September 30, 1997 463,938 $14.54 Granted 624,000 $20.64 Exercised (111,375) $14.60 Canceled (20,879) $16.88 --------------------------------------------------- -------------------------- September 30, 1998 955,684 $18.46 Granted - - Exercised (149,212) $14.66 Canceled (101,680) $20.54 --------------------------------------------------- -------------------------- September 30, 1999 704,792 $18.97 Granted - - Exercised (60,647) $12.86 Canceled - - --------------------------------------------------- -------------------------- --------------------------------------------------- -------------------------- December 31,1999 644,145 $19.08 Granted - - Exercised (644,145) $19.08 Canceled - - --------------------------------------------------- -------------------------- =================================================== ========================== December 31, 2000 - - =================================================== ========================== For purposes of pro forma disclosure, the weighted average fair value at grant date (the value at grant date of the right to purchase stock at a fixed price for an extended time period) for options granted in 1998 was estimated using the Black-Scholes options pricing model with the following weighted average assumptions: Risk free interest rates(s) 5.5% and 5.8% Volatility factor 15.30% Dividend yield 4.53% Expected life 4.5 years The weighted average fair value of nonqualified stock options granted during fiscal 1998 was $2.54. At September 30, 1998, 231,403 options were exercisable at a weighted average price of $13.49. At September 30 and December 31, 1999, all outstanding options were exercisable at the weighted average prices indicated above. As of December 31, 1999, the 644,145 outstanding options had a weighted average remaining contractual life of 2.6 years and exercise prices ranging from $12.86 to $21.25. Employee Stock Purchase Plan Under the 1992 Employee Stock Purchase Plan, as amended, PSNC was authorized to issue common stock to its full-time employees, nearly all of whom were eligible to participate, at a purchase price equal to 90 percent of such common stock's fair value. This plan was terminated effective June 30, 1999. In fiscal 1999 and 1998, PSNC issued to employees 62,355 and 82,203 shares, respectively. For purposes of pro forma disclosure, the weighted average fair value at grant date for employee stock options granted was estimated using the Black-Scholes option pricing model with the following weighted average assumptions: 1999 1998 ------------------------------------------- --------------------- Risk free interest rate 4.58% 5.43% Volatility factor 14.96% 15.30% Dividend yield 3.85% 4.53% Expected life 1 year 1 year The weighted average fair value of each employee stock purchase plan grant during fiscal 1999 and 1998 was $6.52 and $6.10, respectively. 7. LONG-TERM DEBT The annual amounts of long-term debt maturities for the years 2001 through 2005 are summarized as follows: ----------------- ----------------- ------------------ ----------------- Year Amount Year Amount ----------------- ----------------- ------------------ ----------------- (Millions of Dollars) 2001 $4.3 2004 $7.5 2002 4.3 2005 3.2 2003 7.5 ----------------- ----------------- ------------------ ----------------- Under the terms of the debt agreements, there are various provisions relating to the maintenance of certain financial ratios and conditions, the most significant of which could restrict payment of dividends. At December 31, 2000, PSNC is in compliance in all material respects with the requirements of its debt agreements. 8. SHORT-TERM BORROWINGS PSNC pays fees to banks as compensation for its committed lines of credit. Commercial paper borrowings are for 270 days or less. At December 31, 2000 committed lines of credit under revolving credit agreements which expire July 27, 2001 were $125 million. Unused lines of credit were $125 million. Short-term borrowings through commercial paper at December 31, 2000 were $125 million at a weighted average interest rate of 6.69 percent. At December 31, 1999 PSNC had committed lines of credit with five commercial banks and a five-year revolving line of credit with one bank. PSNC also had uncommitted annual lines of credit. PSNC paid fees to banks as compensation for its committed lines of credit. At December 31, 1999 PSNC had authorized lines of credit (committed and uncommitted) of $195 million, which included unused lines of credit of $57.5 million and short-term borrowings of $137.5 million at a weighted average interest rate of 5.74 percent. 9. COMMON EQUITY The changes in "Common Equity" during the year ended December 31, 2000, the three months ended December 31, 1999 and fiscal years ended September 30, 1999 and 1998 are summarized as follows: Common Shares Millions of Dollars -------------------------------------------------------------------------------- Balance at September 30, 1997 19,770,843 $207.4 Changes in Retained Earnings: Net income 24.8 Cash Dividends Declared (19.2) Issuance of Stock 503,489 9.8 -------------------------------------------------------------------------------- Balance at September 30, 1998 20,274,332 222.8 Changes in Retained Earnings Net Income 24.5 Cash Dividends Declared (20.8) Issuance of Stock 303,635 6.7 -------------------------------------------------------------------------------- Balance at September 30, 1999 20,577,967 233.2 Changes in Retained Earnings: Net Income 5.1 Cash Dividends Declared (6.0) ----------------------------------------------- -------------- Balance at December 31, 1999 20,577,967 232.3 Cancellation of Shares Due to Acquisition (20,576,967) 470.9 Other Changes in Retained Earnings: Net Income 27.8 Cash Dividends Declared (19.0) ------------------------------------------------------------------------------- Balance at December 31, 2000 1,000 $712.0 ============================================================== ======= ========= 10. INCOME TAXES Total income tax expense attributable to income before cumulative effect of accounting change for the periods indicated is as follows: Successor Predecessor --------------------------------------------------- ---------------- --------------------------------------------------- Year Three Months Ended Ended Fiscal Year Ended December 31, December 31, September 30, September 30, Millions of dollars 2000 1999 1999 1998 --------------------------------------------------- ---------------- ----------------- ----------------- --------------- Current taxes: Federal $18.6 $2.9 $9.0 $7.9 State 3.9 0.6 2.1 1.8 --------------------------------------------------- ---------------- ----------------- ----------------- --------------- --------------------------------------------------- ---------------- ----------------- ----------------- --------------- Total current taxes 22.5 3.5 11.1 9.7 --------------------------------------------------- ---------------- ----------------- ----------------- --------------- --------------------------------------------------- ---------------- ----------------- ----------------- --------------- Deferred taxes, net: Federal 1.5 0.6 5.4 5.6 State 0.3 0.1 1.2 1.3 --------------------------------------------------- ---------------- ----------------- ----------------- --------------- --------------------------------------------------- ---------------- ----------------- ----------------- --------------- Total deferred taxes 1.8 0.7 6.6 6.9 --------------------------------------------------- ---------------- ----------------- ----------------- --------------- --------------------------------------------------- ---------------- ----------------- ----------------- --------------- Investment tax credits: Amortization of amounts deferred - Federal (0.4) - (0.4) (0.4) --------------------------------------------------- ---------------- ----------------- ----------------- --------------- Total investment tax credits (0.4) - (0.4) (0.4) --------------------------------------------------- ---------------- ----------------- ----------------- --------------- Total income tax expense $23.9 $4.2 $17.3 $16.2 =================================================== ================ ================= ================= =============== The difference between actual income tax expense and the amount calculated from the application of the statutory Federal income tax rate (35% for 2000, 1999 and 1998) to pre-tax income before cumulative effect of accounting change is reconciled as follows: Successor Predecessor --------------------------------------------------- ---------------- --------------------------------------------------- Year Three Months Ended Ended Fiscal Year Ended December 31, December 31, September 30, September 30, Millions of dollars 2000 1999 1999 1998 --------------------------------------------------- ---------------- ----------------- ----------------- --------------- Income before cumulative effect of accounting change $21.2 $5.1 $24.1 $24.8 Total income tax expense: Charged to operating expense 20.6 3.8 15.3 15.1 Charged to other income 3.3 0.4 2.0 1.1 =================================================== ================ ================= ================= =============== Total pre-tax income 45.1 9.3 41.4 41.0 =================================================== ================ ================= ================= =============== =================================================== ================ ----------------- ================= =============== Income taxes on above at statutory Federal income tax rate 15.8 3.3 14.5 14.4 Increases (decreases) attributed to: State income taxes (less Federal income tax effect) 2.8 0.5 2.1 2.0 Non-deductible book amortization of acquisition adjustments 4.7 - - - Amortization of Federal investment tax credits (0.4) - (0.4) (0.4) Other differences, net 1.0 0.4 1.1 0.2 --------------------------------------------------- ---------------- ----------------- ----------------- --------------- =================================================== ================ ================= ================= =============== Total income tax expense $23.9 $4.2 $17.3 $16.2 =================================================== ================ ================= ================= =============== The tax effects of significant temporary differences comprising PSNC's net deferred tax liability of $80.7 million at December 31, 2000 and $73.8 million at December 31, 1999 (see Note 1I), are as follows: Successor Predecessor -------------------------------------------------------------------------- Millions of dollars 2000 1999 -------------------------------------------------------------------------- Deferred tax assets: Unamortized investment tax credits $1.0 $1.1 Other postretirement benefits - 2.1 Pension costs - 2.0 Deferred compensation - 1.0 Other 2.9 4.2 ---------------------------------------------------------------- --------- Total deferred tax assets 3.9 10.4 ---------------------------------------------------------------- --------- Deferred tax liabilities: Property, plant and equipment 82.2 80.6 Other 2.4 3.6 ---------------------------------------------------------------- --------- Total deferred tax liabilities 84.6 84.2 ---------------------------------------------------------------- -------- Net deferred tax liability $80.7 $73.8 ================================================================ ========= 11. FINANCIAL INSTRUMENTS The carrying amounts and estimated fair values of PSNC's financial instruments at December 31, 2000 and 1999 are as follows: Millions of dollars 2000 1999 ------------------------------------------- ----------------------------- ------------------------------ Estimated Estimated Carrying Fair Carrying Fair Amount Value Amount Value ------------------------------------------- -------------- -------------- --------------- -------------- Assets: Cash and temporary cash investments $7 $7 $9 $9 Liabilities: Short-term borrowings 125 125 138 138 Long-term debt 149 154 157 156 The information presented herein is based on pertinent information available as of December 31, 2000 and 1999. Although PSNC 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, 2000, and the current estimated fair value may differ significantly from the estimated fair value that date. The following methods and assumptions were used to estimate the fair value of the above classes of financial instruments: o Cash and temporary cash investments are valued at their carrying amounts. o Fair values of long-term debt are based on quoted market prices of the instruments. Settlement of long-term debt may not be possible or may not be considered prudent. o Short-term borrowings are valued at their carrying amounts. 12. COMMITMENTS AND CONTINGENCIES PSNC owns, or has owned, all or portions of seven sites in North Carolina on which manufactured gas plants (MGP) were formerly operated. Intrusive investigation (including drilling, sampling and analysis) has begun at only one site, and the remaining sites have been evaluated using historical records and observations of current site conditions. These evaluations have revealed that MGP residuals are present or suspected at several of the sites. The North Carolina Department of Environment and Natural Resources has recommended that no further action be taken with respect to one site. An environmental due diligence review of PSNC conducted in February 1999 estimated that the cost to remediate the remaining sites would range between $11.3 million and $21.9 million. During the second quarter of 2000, the review was finalized and the estimated liability was recorded. PSNC is unable to determine the rate at which costs may be incurred over this time period. The estimated cost range has not been discounted to present value. PSNC's associated actual costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other potentially responsible parties (PRP). An order of the NCUC dated May 11, 1993 authorized deferral accounting for all costs associated with the investigation and remediation of MGP sites. As of December 31, 2000, PSNC has recorded a liability and associated regulatory asset of $10.2 million, which reflects the minimum amount of the range, net of shared cost recovery from other PRPs. Amounts incurred to date are not material. Management intends to request recovery in future rate case filings of MGP cleanup costs incurred and not recovered from other PRPs and believes that all costs incurred will be recoverable in gas rates. 13. RESTRUCTURING During fiscal 1999, PSNC recorded net restructuring charges of $4.3 million. These charges consisted of severance benefits of $3.7 million, a one-time payment to 152 employees of $1 million in connection with an automobile fleet restructuring, a net curtailment loss on postretirement benefit obligations of $.5 million offset by pension gains of $1.8 million and $.8 million of other restructuring charges. 14. SEGMENT OF BUSINESS INFORMATION PSNC's reportable segments are listed in the following table. Gas Distribution uses operating income to measure profitability, while Energy Marketing, which is comprised solely of SCANA Public Service (formerly Sonat), uses net income to measure profitability. Affiliate revenue is derived from transactions between reportable segments. Prior to December 31, 1999 Sonat was an equity investment and not a segment of business (see Note 4). PSNC did not have deferred tax assets for any period reported. For 2000, adjustments to net income and income tax expense include the cumulative effect of the accounting change described in Note 2. Disclosure of Reportable Segments Millions of dollars ------------------------------ ------------------- ---------------- -------------- ------------------- -------------------- Year Ended Gas Energy All Adjustments/ Consolidated December 31, 2000 Distribution Marketing Other Eliminations Total ------------------------------ ------------------- ---------------- -------------- ------------------- -------------------- External Revenue $432 $141 $ - $(26) $547 Intersegment Revenue - 1 30 (31) - Deprec. & Amort. 42 - - - 42 Operating Income 54 n/a n/a 3 57 Interest Expense 20 - - - 20 Net Income n/a 2 5 21 28 Segment Assets 1,231 35 72 (90) 1,248 Expenditures for Assets 39 - 1 - 40 ------------------------------ ------------------- ---------------- -------------- ------------------- -------------------- Three months Ended Gas Energy All Adjustments/ Consolidated December 31, 1999 Distribution Marketing Other Eliminations Total ------------------------------ ------------------- ---------------- -------------- ------------------- -------------------- External Revenue $81 n/a - - $81 Intersegment Revenue - n/a $27 $(27) - Deprec. & Amort. 7 n/a - - 7 Operating Income 13 n/a n/a - 13 Interest Expense 5 n/a - - 5 Net Income n/a n/a - 5 5 Segment Assets 678 20 58 (58) 698 Expenditures for Assets 12 n/a 1 - 13 ------------------------------ ------------------- ---------------- -------------- ------------------- -------------------- Fiscal Year Ended Gas Energy All Adjustments/ Consolidated September 31, 1999 Distribution Marketing Other Eliminations Total ------------------------------ ------------------- ---------------- -------------- ------------------- -------------------- External Revenue $298 n/a $6 $(6) $298 Intersegment Revenue - n/a 39 (39) - Deprec. & Amort. 26 n/a 1 (1) 26 Operating Income 53 n/a n/a - 53 Interest Expense 18 n/a - - 18 Net Income n/a n/a 2 22 24 Segment Assets 637 n/a 46 (34) 649 Expenditures for Assets 44 n/a 5 - 49 ------------------------------ ------------------- ---------------- -------------- ------------------- -------------------- Fiscal Year Ended Gas Energy All Adjustments/ Consolidated September 31, 1998 Distribution Marketing Other Eliminations Total ------------------------------ ------------------- ---------------- -------------- ------------------- -------------------- External Revenue $330 n/a - - $330 Intersegment Revenue - n/a $87 $(87) - Deprec. & Amort. 25 n/a 1 (1) 25 Operating Income 54 n/a n/a - 54 Interest Expense 18 n/a - - 18 Net Income n/a n/a 1 24 25 Segment Assets 606 n/a 34 (21) 619 Expenditures for Assets 65 n/a 2 - 67 15. SUBSEQUENT EVENTS PSNC Production Corporation and SCANA Public Service Company LLC were sold to SCANA Energy Marketing, Inc., a subsidiary of SCANA Corporation for $4.4 million, which approximates net book value, effective January 1, 2001. On February 16, 2001 PSNC issued $150 million of medium-term notes having an annual interest rate of 6.625 percent and maturing on February 15, 2011. The proceeds from these borrowings were used to reduce short-term debt and for general corporate purposes. 16. QUARTERLY FINANCIAL DATA (UNAUDITED) (Millions of dollars, except per share amounts) -------------------------------------------------------- ------------------------------------------------------------ Year Ended December 31, 2000 First Second Third Fourth Quarter Quarter Quarter Quarter Annual -------------------------------------------------------- ----------- ------------ ----------- ----------- ----------- Total operating revenues $171 $80 $76 $220 $547 Operating income (loss) 37(1) (2) (7) 29 57 Cumulative effect of accounting change, net of taxes 7 - - - 7 Net income (loss) 26 (5) (8) 15 28 Three Months Ended December 31, 1999 -------------------------------------------------------- ----------- Total operating revenues $81 Operating income (loss) 13 Net income (loss) 5 --------------------------------------------------------------------------------------------------- First Second Third Fourth Fiscal Year Ended September 30, 1999 Quarter Quarter Quarter Quarter Annual -------------------------------------------------- ------------ ----------- ----------- ----------- Total operating revenues $73 $135 $54 $37 $299 Operating income (loss) 10 40 7 (3) 54 Net income (loss) 4 22 2 (3) 25 (1)Excludes $14 million of income taxes formerly reported in first quarter operating income. PART II, ITEM 9 AND PART III SCANA CORPORATION SOUTH CAROLINA ELECTRIC & GAS COMPANY PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE: SCANA: None SCE&G: None PSNC filed on April 3, 2000 a Current Report on Form 8-K dated March 27, 2000 changing its certifying accountants. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT SCANA: 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 SCANA Corporation on page 23 herein. The other information required by Item 10 is incorporated herein by reference, to the captions "Proposal 1 - Nominees For Class II Directors", "Continuing Directors", and "Other Information - Section 16(a) Beneficial Ownership Reporting Compliance" in SCANA's definitive proxy statement for the 2001 annual meeting of shareholders which was filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934. SCE&G: DIRECTORS The directors listed below were elected April 27, 2000 (except as otherwise indicated) to hold office until the next annual meeting of SCE&G's stockholders on May 3, 2001. Name and Year First Became Director Age Principal Occupation; Directorships Bill L. Amick 57 For more than five years, Chairman of the Board (1990) and Chief Executive Officer of Amick Farms, Inc., Amick Processing, Inc. and Amick Broilers, Inc., Batesburg, SC (vertically integrated broiler operation). Director, SCANA Corporation, Columbia, SC.; Public Service Company of North Carolina, Inc., (PSNC), Gastonia, NC; Blue Cross and Blue Shield of South Carolina, Columbia, SC. James A. Bennett Since May 2000, President and Chief Executive (1997) 40 Officer of South Carolina Community Bank, Columbia, SC. From February 10, 2000 to May 2000, Economic Development Director, First Citizens Bank, Columbia, SC From December 1998 to February 2000, Senior Vice President and Director of Professional Banking, First Citizens Bank. From December 1994 to December 1998, Senior Vice President and Director of Community Banking, First Citizens Bank. Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC. William B. Bookhart, Jr. (1979) 59 For more than five years, a partner in Bookhart Farms, Elloree, SC (general farming). Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC. Name and Year First Became Director Age Principal Occupation; Directorships William C. Burkhardt 63 Since May 2000, retired President and Chief , (2000) Executive Officer of Austin Quality Foods, Inc. Cary, NC (production and distribution of baked snacks) Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC; Capital Bank, Raleigh, NC. Hugh M. Chapman 68 Since June 30, 1997, retired from NationsBank (1988) South, Atlanta, GA (a division of NationsBank Corporation, bank holding company). For more than five years prior to June 30, 1997 Chairman of NationsBank South. Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC; West Point-Stevens, West Point, GA; PrintPack, Inc., Atlanta, GA; The Williams Companies, Inc., Tulsa, OK. Elaine T. Freeman 65 For more than five years, Executive Director of (1992) ETV Endowment of South Carolina, Inc. (non-profit organization), Spartanburg, SC Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC; National Bank of South Carolina (a member bank of Synovus Financial Corporation), Columbia, SC. Lawrence M. Gressette,Jr. 69 Since February 28, 1997, Chairman Emeritus of (1987) SCANA Corporation, Columbia, SC. For more than five years prior to February 28, 1997, Chairman of the Board and Chief Executive Officer of SCANA Corporation. Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC. D. Maybank Hagood 39 For more than five years, President and Chief (1999) Executive Officer of William M. Bird and Company, Inc., Charleston, SC (wholesale distributor of floor covering materials). Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC. W. Hayne Hipp 61 For more than five years, Chairman, President (1983) and Chief Executive Officer, The Liberty . Corporation, Greenville, SC (broadcasting holding company) Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC; The Liberty Corporation, Greenville, SC; Wachovia Corporation, Winston-Salem, NC. Lynne M. Miller 49 Since February 1998, Chief Executive Officer of (1997) Environmental Strategies Corporation, Reston, VA (environmental consulting and engineering firm). For more than five years prior to February 1998, President of Environmental Strategies Corporation. Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC; Adams National Bank, (a Subsidiary of Abigail Adams National Bancorp, Inc.), Washington, DC. Name and Year First Became Director Age Principal Occupation; Directorships Maceo K. Sloan 51 For more than five years, Chairman, President (1997) and Chief Executive Officer of Sloan Financial Group, Inc. (holding company) and Chairman and Chief Executive Officer of NCM Capital Management Group, Inc. (investment company), Durham, NC. Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC; M&F Bankcorp, Inc., and Its subsidiary, Mechanics and Farmers Bank, Durham, NC; NetDirect, Minneapolis, MN., and Trustee of Teachers Insurance Annuity Association - College Retirement Equity Fund (TIAA- CREF). Harold C. Stowe 54 Since March 1997, President and Chief (1999) Executive Officer of Canal Industries, Inc., Conway, SC (forest products industry). From 1996 to March 1997, Co-President of Canal Industries, Inc. From 1991 to 1996, Executive Vice President of CSI Group, Inc., a division of Canal Industries, Inc. Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC; Canal Industries, Inc., Conway, SC; Ruddick Corporation, Charlotte, NC. William B. Timmerman 54 Since March 1, 1997, Chairman and Chief (1991) Executive Officer of SCANA Corporation, Columbia, SC. From at least March 1, 1996, President of SCANA Corporation. From August 21, 1996 to March 1, 1997, Chief Operating Officer of SCANA Corporation. Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC; Powertel, Inc., West Point, GA; ITC^DeltaCom, Inc. West Point, GA; The Liberty Corporation, Greenville, SC. G. Smedes York 60 For more than five years, President and (2000) Raleigh, NC.Treasurer of York Properties, Inc. (full-service commercial and residential real estate company). Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC. Charles E. Zeigler, Jr. 54 Since February 2000, President and Chief (2000) Operating Officer of PSNC, Gastonia, NC. From February 1993 to February 2000, Chairman, President and Chief Executive Officer of PSNC. Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC. EXECUTIVE OFFICERS OF SCE&G SCE&G's officers are elected at the annual organizational meeting of the Board of Directors and hold office until the next such organizational meeting, unless the Board of Directors shall otherwise determine, or unless a resignation is submitted. Positions Held During Name Age Past Five Years Dates W. B. Timmerman 54 Chairman of the Board and Chief Executive Officer 1997-present President, SCANA *-present Chief Operating Officer, SCANA 1996-1997 President, SCI, an affiliate 1996-1997 Chief Financial Officer and Controller, SCANA *-1996 H. T. Arthur 55 Senior Vice President and General Counsel 1998-present Vice President and General Counsel 1996-1998 N. O. Lorick 50 President and Chief Operating Officer 2000-present Vice President of Fossil and Hydro Operations *-2000 K. B. Marsh 45 Senior Vice President - Finance and Chief Financial Officer 2000-present Senior Vice President - Finance, Chief Financial Officer and Controller, SCANA 1998-2000 Vice President - Finance, Chief Financial Officer and Controller, SCANA 1996-1998 Vice President - Finance, Treasurer and Secretary, SCE&G *-1996 S. A. Byrne 40 Vice President Nuclear Operations 2000-present General Manager Nuclear Plant Operations *-2000 M. R. Cannon 50 Controller, SCANA & All Subsidiaries (excluding SEMI) 2000-present Treasurer, SCANA & SCE&G *-2000 *Indicates position held at least since March 1, 1996 SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE All of SCE&G's common stock is held by its parent, SCANA Corporation. The required forms indicate that no equity securities of SCE&G are owned by its directors and executive officers. Based solely on a review of the copies of such forms and amendments furnished to SCE&G and written representations from the executive officers and directors, SCE&G believes that during 2000 all Section 16(a) filing requirements applicable to its executive officers, directors and greater than 10 percent beneficial owners were complied with. ITEM 11. EXECUTIVE COMPENSATION SCANA: The information called for by Item 11, Executive Compensation, is incorporated herein by reference to the captions "Director Compensation," "Compensation Committee Interlocks and Insider Participation," and "Executive Compensation" in SCANA's definitive proxy statement for the 2001 annual meeting of shareholders. SCE&G: The information called for by Item 11, Executive Compensation, is as follows: Summary Compensation Table Annual Compensation Long-Term Compensation Awards Securities Underlying Option LTIP Salary Bonus(1) Compensation(2) SARS Payouts(3) Compensation(4) Name and Principal Position Year ($) ($) ($) (#) ($) ($) ---- W. B. Timmerman 2000 524,261(5) 354,486 17,888 35,620 - 50,230 Chairman, President and Chief 1999 490,313 312,900 17,212 - 298,813 29,419 Executive Officer - SCANA 1998 455,909 303,780 17,514 - - 27,138 J. L. Skolds 2000 244,086 - 12,878 - - 24,743 Former President and Chief 1999 330,665 168,288 16,232 - 150,618 19,840 Operating Officer - SCE&G 1998 305,123 163,399 14,099 - - 18,201 N. O. Lorick 2000 167,778 124,921 7,313 2,332 - 12,728 President and Chief Operating 1999 157,417 44,356 7,313 - 38,754 9,445 Officer - SCE&G 1998 143,492 46,719 4,813 - - 8,613 K. B. Marsh 2000 276,172 150,720 10,613 11,627 - 24,254 Senior Vice President - Finance 1999 241,354 128,058 10,337 - 81,555 14,481 and Chief Financial Officer - 1998 219,860 99,372 8,654 - - 13,122 SCANA H. T. Arthur 2000 234,812 120,480 16,119 8,796 - 19,718 Senior Vice President and 1999 219,806 93,825 15,939 - 65,843 13,188 General Counsel 1998 203,162 99,372 9,534 - - 12,190 S. A. Byrne 2000 183,555 123,492 8,310 8,796 - 12,962 Vice President Nuclear 1999 137,321 32,483 3,600 - - 8,239 Operations 1998 125,458 38,682 2,100 - - 7,528 (1) Payments under the Annual Incentive Plan. (2) For 2000, other annual compensation consists of automobile allowance, life insurance premiums on policies owned by named executive officers and payments to cover taxes on benefits of $9,000, $7,435 and $1,453 for Mr. Timmerman; $6,000, $6,878 and $0 for Mr. Skolds; $6,000, $1,313 and $0 for Mr. Lorick; $9,000, $1,183 and $430 for Mr. Marsh; $9,000, $6,830, and $289 for Mr. Arthur and $8,100, $0 and $210 for Mr. Byrne. (3) Payments under the Long-term Equity Compensation Plan. (4) All other compensation for all named executive officers consists solely of contributions to defined contribution plans. (5) Reflects actual salary paid in 2000. Base salary of $537,100, became effective on May 1, 2000. (6) Mr. Skolds resigned from SCE&G on August 18, 2000. Options Grants and Related Information Options/SAR Grants in Last Fiscal Year Potential Realizable Value at Assumed Annual Rates of Stock Price Appreciation Individual Grants for Option Term ----------------------------------------------------------------------------------------- --------------------------- (a) (b) (c) (d) (e) (f) (g) Number of % of Total Securities Options/ Underlying SARs Options/ Granted to Exercise or SARs Employees in Base Price Expiration Name Granted Fiscal Year ($/Sh) Date 5% ($) 10%($) ----------------------- --------------- ---------------- ---------------- --------------- --------------- ----------- W. B. Timmerman 35,620 22.20 25.50 04/27/10 571,345 1,447,597 N. O. Lorick 2,332 1.45 25.50 04/27/10 37,405 94,772 K. B. Marsh 11,627 7.25 25.50 04/27/10 186,497 472,521 H. T. Arthur 8,796 5.48 25.50 04/27/10 141,088 357,469 S. A. Byrne 8,796 5.48 25.50 04/27/10 141,088 357,469 All the above options vest 33 1/3 percent on each of the first, second and third anniversaries of the date of the grant, April 27, 2000. Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values (a) (d) (e) Number of Securities Underlying Value of Unexercised Unexercised In-the-Money Options/ Option/SARs SARs at At FY-End (#) FY-End ($) (1) Exercisable/ Exercisable/ Name Unexercisable Unexercisable --------------------------------------- -------------------------------------- -------------------------------------- W. B. Timmerman 0/35,620 0/144,724 N. O. Lorick 0/2,332 0/9,475 K. B. Marsh 0/11,627 0/47,240 H. T. Arthur 0/8,796 0/35,738 S. A. Byrne 0/8,796 0/35,738 (1)Based on the closing price of $29.5625 per share on December 29, 2000, the last trading date of the fiscal year. The following table lists the performance share awards made in 2000 (for potential payment in 2003) under the Long-Term Equity Compensation Plan and estimated future payouts under that plan at threshold, target and maximum levels for each of the executive officers included in the Summary Compensation Table. LONG-TERM INCENTIVE PLANS AWARDS IN LAST FISCAL YEAR Number of Performance Estimated Future Payouts Under Shares, or Other Non-Stock Price-Based Plans --------------------------------------------------------- Units or Period Until Other Maturation Threshold Target Maximum Name Rights (#) or Payout (#) (#) (#) ---------------------- ---------------- ------------------- ------------------ ------------------ ------------------- W. B. Timmerman 12,510 2000-2002 5,004 12,510 18,765 N. O. Lorick 3,390 2000-2002 1,356 3,390 5,085 K. B. Marsh 4,880 2000-2002 1,952 4,880 7,320 H. T. Arthur 3,410 2000-2002 1,364 3,410 5,115 S. A. Byrne 3,410 2000-2002 1,364 3,410 5,115 Payouts occur when SCANA's Total Shareholder Return is in the top two-thirds of the Long-Term Equity Compensation Plan peer group, and will vary based on SCANA's ranking against the peer group. Executives earn threshold payouts at the 33rd percentile of three-year performance. Target payouts will be made at the 50th percentile of three-year performance. Maximum payouts will be made when performance is at or above the 75th percentile of the peer group. Payments will be made on a sliding scale for performance between threshold and target and target and maximum. No payouts will be earned if performance is at less than the 33rd percentile. Awards are designated as target shares of SCANA Common Stock and may be paid in stock or a combination of stock and cash. DEFINED BENEFIT PLANS Effective January 1, 2000, the SCANA Corporation Retirement Plan, a tax qualified defined benefit plan, was amended to provide a mandatory cash balance benefit formula (the "Cash Balance Formula") for employees hired on or after that date. Effective July 1, 2000, SCANA employees hired prior to January 1, 2000, were given the choice of remaining under the Retirement Plan's final average pay benefit formula or switching to a cash balance benefit option. The Cash Balance Formula benefit is expressed in the form of a hypothetical account balance. Participants electing to participate under the cash balance option had an opening account balance established for them. The opening account balance equals the present value of the participant's June 30, 2000 accrued benefit under the final average pay formula. Participants who had 20 years of vesting service or who had 10 years of vesting service and whose age plus service equaled at least 60 were given transition credits. For these participants the beginning account balance was determined so that projected benefits under the cash balance option approximated projected benefits under the final average pay formula at the earliest date at which unreduced benefits are payable under the plan. Account balances are increased monthly by interest and compensation credits. The interest rate used for accumulating account balances changes annually and is equal to the rate for 30-year Treasuries for December of the previous calendar year. Compensation credits equal 5 percent of compensation under the Social Security Wage Base and 10 percent of compensation in excess of the Social Security Wage Base. In addition to its Retirement Plan for all employees, SCANA has Supplemental Executive Retirement Plans ("SERPs") for certain eligible employees, including certain officers of its subsidiaries. A SERP is an unfunded plan that provides for benefit payments in addition to benefits payable under the qualified Retirement Plan so as to make up for benefits lost in the Retirement Plan because of Internal Revenue Code maximum benefit limitations. All the executive officers named in the Summary Compensation Table are participating under the cash balance benefit option of the plan. The estimated annual retirement benefits payable as life annuities at age 65 under the plans, based on projected compensation (assuming increases of 4 percent per year), to the executive officers named in the Summary Compensation Table are as follows: Mr. Timmerman - $410,496; Mr. Lorick - $224,448; Mr. Marsh - $ 278,220; Mr. Arthur - $122,424 and Mr. Byrne - $158,258. SCANA has a Key Employee Retention Plan ("KERP") covering officers and certain other executive employees of SCE&G that provide supplemental retirement or death benefits for participants. These employees also participate in SCANA's Retirement Plan. Participants who elected to remain in the final average pay plan continue to participate in the KERP under the provisions in effect on June 30, 2000. Each participant who elected to convert to the cash balance plan became entitled on July 1, 2000 to a KERP cash balance benefit. The amount of the benefit was determined by discounting to June 30, 2000 the amount of the participant's projected retirement benefit under the prior plan, assuming the participant retired upon attaining the earlier of (i) age 65 or (ii) 35 years of service (unreduced retirement age), adjusted to reflect actual years of service through June 30, 2000. Each participant's account balance will increase in each subsequent year until unreduced retirement age by (i) interest at the rate for 30-year Treasuries and (ii) an accrual reflecting one additional year of service. If a participant continues to work beyond his unreduced retirement age, his KERP account will only grow with interest. In the event of the participant's death prior to such retirement, SCANA will pay to the participant's designated beneficiary, the participant's KERP account balance at the time of death. In the event a participant's employment is terminated prior to retirement, the participant will be paid his KERP account balance. The estimated annual retirement benefits payable at age 65 under the KERP to the executive officers named in the Summary Compensation Table, who participate in the KERP, based on projected eligible compensation (assuming increases of 4 percent per year) are: Mr. Timmerman - $ 186,357; Mr. Marsh - $146,464; Mr. Arthur - $80,086; Mr. Lorick - $84,677 and Mr. Byrne - $120,183. TERMINATION, SEVERANCE AND CHANGE IN CONTROL ARRANGEMENTS SCANA maintains an Executive Benefit Plan Trust. The purpose of the trust is to help retain and attract quality leadership in key SCANA positions in the current transitional environment of the utilities industry. The trust is used to receive SCANA contributions which may be used to pay the deferred compensation benefits of certain directors, executives and other key employees of SCANA in the event of a Change in Control (as defined in the trust). (1) SCANA Corporation Supplementary Voluntary Deferral Plan (2) SCANA Corporation Key Employee Retention Plan (3) SCANA Corporation Supplemental Executive Retirement Plan (4) SCANA Corporation Long-term Equity Compensation Plan (5) SCANA Corporation Annual Incentive Plan (6) SCANA Corporation Key Executive Severance Benefits Plan (7) SCANA Corporation Supplementary Key Executive Severance Benefits Plan The trusts and the plans provide flexibility to SCANA in responding to a Potential Change in Control (as defined in the trust) depending upon whether the Change in Control would be viewed as being "hostile" or "friendly." This flexibility includes the ability to deposit and withdraw SCANA contributions up to the point of a Change in Control, and to affect the number of plan participants who may be eligible for benefit distributions upon, or following, a Change in Control. The Key Executive Severance Benefits Plan is operative as a "single trigger" plan, meaning that upon the occurrence of a "hostile" Change in Control, benefits provided under Plans (1) through (5) above would be distributed in a lump sum. In contrast, the Supplementary Key Executive Severance Benefits Plan is operative for a period of 24 months following a Change in Control which prior to its occurrence is viewed as being "friendly." In this circumstance, the Key Executive Severance Benefits Plan is inoperative. The Supplementary Key Executive Severance Benefits Plan is a "double trigger" plan that would pay benefits in lieu of those otherwise provided under Plans (1) through (5) in either of two circumstances: (a) the participant's involuntary termination of employment without "Just Cause", or (b) the participant's voluntary termination of employment for "Good Reason" (as these terms are defined in the Supplementary Key Executive Severance Benefits Plan). Benefit distributions relative to a Change in Control, as to which either the Key Executive Severance Benefits Plan or the Supplementary Key Executive Severance Benefits Plan is operative, will be grossed up to include estimated federal, state and local income taxes and any applicable excise taxes owed by plan participants on those benefits. The benefit distributions under the Key Executive Severance Benefits Plan would include the following: o An amount equal to three times the sum of: (1) the officer's annual base salary in effect as of the Change in Control and (2) the larger of (i) the officer's target award in effect as of the Change in Control under the Annual Incentive Plan or (ii) the officer's average of actual annual incentive bonuses received during the prior three years under the Annual Incentive Plan. o An amount equal to the projected cost for coverage for three full years following the Change in Control as though the officer had continued to be a SCANA employee with respect to medical coverage, long-term disability coverage and either Life Plus (a special life insurance program combining whole life and term coverages) or group term life coverage in accordance with the officer's election, in each case so as to provide substantially the same level of coverage and benefits as the officer enjoyed as of the date of the Change in Control. o A benefit distribution under the Supplementary Voluntary Deferral Plan calculated to include any implied dividends accrued under the plan through the date of the Change in Control. o A benefit distribution under the Key Employee Retention Plan equal to the lump sum amount calculated as of the day of the Change in Control under the KERP cash balance formula. o A benefit distribution under the Supplemental Executive Retirement Plan ("SERP") equal to the amount of the SERP cash balance account as of the date of the Change in Control, increased by an amount equal to additional compensation and interest credits, assuming the executive had completed three additional years of service with compensation at the participant's rate of compensation then in effect, and assuming interest credits for three additional years at the applicable rate of interest, which benefit would then be reduced by the amount of the participant's cash balance account accrued under the Retirement Plan as of the date the Change in Control. o A benefit distribution under the Performance Share Plan equal to 100 percent of the targeted awards for all performance periods not completed as of the date of the Change in Control. o A benefit distribution under the Long-Term Equity Compensation Plan equal to 100 percent of the targeted performance share awards for all performance periods not completed as of the date of the Change in Control. o Under the Long-Term Equity Compensation Plan, all nonqualified stock options awarded shall become immediately exercisable and remain exercisable throughout their term. o A benefit distribution under the Annual Incentive Plan equal to 100 percent of the target award in effect as of the date of the Change in Control. Benefits under the Supplementary Key Employee Severance Benefits Plan would be the same except that the benefits under the Supplementary Voluntary Deferral Plan would be increased by implied interest from the date of the Change in Control until the end of the month preceding the month in which the benefit is distributed. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION During 2000, decisions on various elements of executive compensation were made by the Management Development and Corporate Performance Committee and the Long-Term Equity Compensation Plan Committee. No officer, employee or former officer of SCANA or any of its subsidiaries served as a member of the Management Development and Corporate Performance Committee or the Long-Term Equity Compensation Plan Committee except Mr. Timmerman, who served as an ex-officio, non-voting member of the Management Development and Corporate Performance Committee. The names of the persons who serve on the Management Development and Corporate Performance Committee and the Long-Term Equity Compensation Plan Committee can be found at Item 12, Security Ownership of Certain Beneficial Owners and Management. Although Mr. Timmerman served as a member of the Management Development and Corporate Performance Committee, he did not participate in any of its decisions concerning executive officer compensation. During 2000, SCANA and its subsidiaries engaged in a business transaction with an entity with which Mr. Amick (a member of the Management Development and Corporate Performance Committee) is related. Mr. Amick is President and a 20 percent owner of Team Amick Motorsports LLC, a business that owns and operates a NASCAR sanctioned racing car. This car participates in the Busch Grand National Racing Series. During 2000, SCANA and its subsidiaries paid Team Amick Motorsports, LLC a total of $254,085, for a sponsorship and car appearances pursuant to which SCANA received promotional considerations associated with NASCAR racing. SCANA and its subsidiaries do not plan to continue as a sponsor with Team Amick Motorsports, LLC in 2001. Directors Compensation Board Fees Officers of SCANA who are also directors do not receive additional compensation for their service as directors. Since July 1, 2000, compensation for non-employee directors of SCANA has included the following: o an annual retainer of $30,000 (60 percent of the annual retainer fee is paid in shares of SCANA Common Stock); o $3,500 for each board meeting attended; o $3,000 for attendance at a committee meeting held on a day other than a regular meeting of the Board; o $250 for participation in a telephone conference meeting; o $2,000 for attendance at an all-day conference; and o reimbursement for expenses incurred in connection with all of the above. Director Compensation and Deferral Plans During 2000, non-employee directors could participate in SCANA's Voluntary Deferral Plan. This plan permitted non-employee directors to defer receipt of all or part of their fees (except the portion paid in shares of SCANA Common Stock) and receive, upon ceasing to serve as a director, the amount that would have resulted from investing the deferred amounts in an interest bearing savings account. During calendar year 2000, Mr. Bennett deferred compensation under the Voluntary Deferral Plan and his account was credited with interest in the amount of $2,669 for that year. Effective January 1, 2001, non-employee director compensation deferrals are governed by a new plan, the SCANA Corporation Director Compensation and Deferral Plan. Amounts deferred by directors in previous years under the SCANA Voluntary Deferral Plan continue to be governed by that plan. Under the new plan, a director may elect to defer (i) 100 percent of all compensation amounts , or (ii) the 60 percent of the annual retainer fee required to be paid in SCANA Common Stock, in a hypothetical investment in SCANA Common Stock, with distribution from the plan to be ultimately payable in actual shares of SCANA Common Stock. A director also may elect to defer the 40 percent of the annual retainer fee not required to be paid in shares of SCANA Common Stock and up to 100 percent of meeting attendance and conference fees with distribution from the plan to be ultimately payable in either SCANA Common Stock or cash. Amounts payable in SCANA Common Stock accrue earnings during the deferral period at SCANA's dividend rate, which amount may be elected to be paid in cash when accrued or retained to invest in hypothetical shares of SCANA Common Stock. Amounts payable in cash accrue interest earnings until paid. For calendar year 2001, Messrs. Amick, Bennett, Burkhardt, Hipp, Sloan, Stowe and York and Ms. Miller have elected to defer 100 percent of their compensation under the Director Compensation and Deferral Plan so as to acquire hypothetical shares of SCANA Common Stock. In addition, Mr. Hagood has elected to defer 60 percent of his annual retainer to acquire hypothetical shares of SCANA Common Stock. Endowment Plan. Upon election to a second term, a director becomes eligible to participate in the SCANA Director Endowment Plan, which provides for SCANA to make a tax deductible, charitable contribution totaling $500,000 to institutions of higher education designated by the director. The plan is intended to reinforce SCANA's commitment to quality higher education designated by the director. The plan is intended to reinforce SCANA's commitment to quality higher education and to enhance its ability to attract and retain qualified board members. A portion is contributed upon retirement of the director and the remainder upon the director's death. The plan is funded in part through insurance on the lives of the directors. Designated in-state institutions of higher education must be approved by the Chief Executive Officer of SCANA. Any out-of-state designation must be approved by the Management Development and Corporate Performance Committee. The designated institutions are reviewed on an annual basis by the Chief Executive Officer to assure compliance with the intent of the program. Other As a Company retiree, Mr. Gressette receives monthly retirement benefits of $39,571. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT SCANA: The information called for by Item 12, Security Ownership of Certain Beneficial Owners and Management is incorporated herein by reference to the caption "Share Ownership of Directors, Nominees and Executive Officers" and "Five Percent Owner of SCANA Common Stock" in SCANA's definitive proxy statement for the 2001 annual meeting of shareholders. SCE&G: All of the outstanding voting securities of SCE&G are owned by SCANA. The following table lists shares of SCANA common stock beneficially owned on March 9, 2001 by each director, each nominee and each executive officer named in the Summary Compensation table on page 141. SECURITY OWNERSHIP OF MANAGEMENT Amount and Nature Amount and Nature of Beneficial Ownership of of Beneficial Ownership of SCANA Common Stock *(1)(2)(3)(4) SCANA Common Stock *(1)(2)(3)(4) Name Name ----- ------------------------------ ---- B. L. Amick(5) 11,821 W. H. Hipp 4,896 H. T. Arthur 16,211 K. B. Marsh 18,826 J. A. Bennett(6) 2,210 L. M. Miller(6) 3,356 W. B. Bookhart, Jr.(5)(6) 21,811 N. O. Lorick 15,977 W. C. Burkhardt(5)(6) 11,130 M. K. Sloan(5)(6) 3,955 S. A. Byrne 7,467 H. C. Stowe(5)(6) 3,941 H. M. Chapman(5)(6) 7,994 W. B. Timmerman(5) 65,191 E. T. Freeman 6,435 G. S. York(6) 10,744 L. M. Gressette, Jr. 63,640 C. E. Zeigler, Jr. 32,133 D. M. Hagood(6) 820 *Each of the directors, nominees and named executive officers owns less than 1 percent of the shares outstanding. All directors and executive officers as a group ( persons) TOTAL .TOTAL PERCENT OF CLASS, outstanding and entitled to vote at the Annual Meeting of Shareholders percent.---------- (1) Includes shares owned by close relatives, the beneficial ownership of which is disclaimed by the director, nominee or named executive officers, as follows: Mr. Amick-480; Mr. Bookhart-5,804; Mr. Gressette-1,060; and by all directors, nominees and executive officers 7,344 in total. (2) Includes shares purchased through February 28, 2001, by the Trustee under SCANA's Stock Purchase Savings Plan. (3) Hypothetical shares acquired under the SCANA Director Compensation and Deferral Plan are not included in the above table. As of March 9, 2001, each of Messrs. Amick, Bennett, Burkhardt, Hipp, Sloan, Stowe and York and Ms. Miller had acquired 674 hypothetical shares under the plan and Mr. Hagood had acquired 404. (4) Includes shares subject to options exercisable within 60 days. (5) Serves on The Management Development and Corporate Performance Committee (Mr. Timmerman serves as an ex-officio, non-voting member). (6) Serves on the Long-Term Equity Compensation Plan Committee. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS SCANA: The information called for by Item 13, Certain Relationships and Related Transactions is incorporated herein by reference to the captions "Compensation Committee Interlocks and Insider Participation" and "Related Transactions" in SCANA's definitive proxy statement for the 2001 annual meeting of stockholders. 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 on Executive Compensation", the "Performance Graph" and the "Audit Committee Report" included in SCANA's definitive proxy statement for the 2001 annual meeting of shareholders shall not be incorporated by reference into any such filings. SCE&G: For information regarding certain relationships and related transactions, see Item 11, Executive Compensation under the heading Compensation Committee Interlocks and Insider Participation and the following: During 2000, SCANA paid $239,242 (including the value of non-utility in kind services provided by SCANA) to subsidiaries of Liberty Corporation for advertising expenses. Mr. Hipp is the Chairman, President and Chief Executive Officer and a director of Liberty Corporation. It is anticipated that similar transactions will occur in the future. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) The following documents are filed as a part of this report on this Form 10-K: (1) Financial Statements and Schedules: The Independent Auditor's Reports on the financial statements for SCANA, SCE&G and PSNC are listed under Item 8 herein. The financial statements and supplementary financial data filed as part of this report for SCANA, SCE&G and PSNC are listed under Item 8 herein. The Financial Statement Schedules filed as part of this report for SCANA, SCE&G and PSNC are listed beginning on page 150. (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 Securities and Exchange Commission and which are designated by reference to their exhibit number 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 report for SCANA's employee stock purchase 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 SCANA, for itself and its subsidiaries, of SCE&G, for itself and its subsidiaries, and of PSNC, for itself and its subsidiaries, have been omitted and SCANA, SCE&G and PSNC agree to furnish a copy of such instruments to the Commission upon request. (b) Reports on Form 8-K during the fourth quarter of 2000 for SCANA, SCE&G and PSNC: None SCANA: Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2000, 1999 and 1998. For December 31, 2000 Additions Charged to Beginning Charged to Other Deductions Ending Description Balance Income Accounts from Reserves Balance -------------------------------------- ---------------- ---------------- --------------- ---------------- ---------------- Reserves deducted from related assets on the balance sheet: Uncollectible accounts 2000 7,302,273 23,308,561 - 77,133 30,533,701 1999 1,965,732 5,636,123 - 299,582 7,302,273 1998 1,807,047 184,257 - 25,572 1,965,732 Reserve for investment impairment 2000 4,133,768 1,000,000 - 205,000 4,928,768 1999 10,292,611 - - 6,158,843 4,133,768 1998 11,150,060 - - 857,449 10,292,611 Reserves other than those deducted from assets on the balance sheet: Reserve for injuries and damages 2000 5,221,544 2,461,339 - 333,544 7,349,339 1999 4,287,986 1,352,448 - 418,890 5,221,544 1998 4,187,594 461,462 - 361,070 4,287,986 Provision for pension and benefit Staff Reduction Plan 2000 6,487,365 - - 131,570 6,355,795 1999 6,256,249 231,116 - - 6,487,365 1998 4,486,895 6,256,249 - 4,486,895 6,256,249 Provision for environmental remediation and settlement 2000 3,223,821 - - 409,252 2,814,569 1999 3,619,572 - - 395,751 3,223,821 1998 4,006,562 - - 386,990 3,619,572 SCE&G: Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2000, 1999 and 1998. For December 31, 2000 Additions Beginning Charged to Charged to Deductions Ending Description Balance Income Other Accounts From Reserves Balance -------------------------------------- ---------------- ---------------- --------------- ---------------- ---------------- Reserves deducted from related assets on the balance sheet: Uncollectible accounts 2000 537,000 116,000 - 76,000 577,000 1999 611,001 80,000 154,001 537,000 1998 611,001 - - - 611,001 Reserves other than those deducted from assets on the balance sheet: Reserve for injuries and damages 2000 3,972,816 819,431 - 217,055 4,575,192 1999 4,176,794 104,000 - 307,978 3,972,816 1998 4,039,148 460,462 - 322,816 4,176,794 Provision for pension and benefit Staff Reduction Plan 2000 - - - - - 1999 - - - - - 1998 4,486,895 - - 4,486,895 - Provision for environmental remediation and settlement 2000 3,223,821 - - 409,252 2,814,569 1999 3,619,572 - - 395,751 3,223,821 1998 4,006,562 - - 386,990 3,619,572 PSNC: Schedule II - Valuation and Qualifying Accounts for the Year Ended December 31, 2000, Three Months Ended December 31, 1999 and Fiscal Years Ended September 30, 1999 and 1998. For December 31, 2000 Additions Beginning Charged to Charged to Deductions Ending Description Balance Income Other Accounts from Reserves Balance -------------------------------- ---------------------- ---------------- --------------- ---------------- ---------------- Reserves deducted from related assets on the balance sheet: Uncollectible accounts 2000 2,702,014 2,417,566 - 2,716,884 2,402,696 Three Months 1999 1,737,815 470,895 - (199,069) 2,702,014* Fiscal Year 1999 2,086,128 725,094 - 1,073,407 1,737,815 Fiscal Year 1998 2,521,983 866,786 - 1,302,641 2,086,128 Reserves other than those deducted from assets on the balance sheet: Reserve for injuries and damages 2000 2,197,615 494,629 - 1,065,986 1,626,258 Three Months 1999 1,930,377 442,000 - 174,762 2,197,615 Fiscal Year 1999 1,207,278 1,802,544 - 1,079,445 1,930,377 Fiscal Year 1998 1,131,780 1,422,271 - 1,346,773 1,207,278 Provision for post-retirement & post-employment 2000 6,658,753 1,227,823 - 7,488,576 398,000 Three Months 1999 6,466,563 298,857 - 106,667 6,658,753 Fiscal Year 1999 5,165,324 1,676,767 - 375,528 6,466,563 Fiscal Year 1998 4,436,674 1,052,990 - 324,340 5,165,324 *Ending balance for December 31, 1999 includes $294,235 uncollectible reserve balance for SCANA Public Service Company, L.L.C. (formerly Sonat Public Service) purchased December 31, 1999. 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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. SCANA CORPORATION s/W. B. Timmerman By: W. B. Timmerman, Chairman of the Board, President, Chief Executive Officer and Director DATE: March 27, 2001 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. s/W. B. Timmerman W. B. Timmerman, Chairman of the Board, President, Chief Executive Officer and Director (Principal Executive Officer) s/K. B. Marsh K. B. Marsh, Senior Vice President - Finance, Chief Financial Officer (Principal Financial Officer) s/ M. R. Cannon M. R. Cannon, Controller (Principal Accounting Officer) Other Directors*: B. L. Amick D. M. Hagood J. A. Bennett W. H. Hipp W. B. Bookhart, Jr. L. M. Miller W. C. Burkhardt M. K. Sloan H. M. Chapman H. C. Stowe E. T. Freeman G. S. York L. M. Gressette, Jr. C. E. Zeigler, Jr. *Signed on behalf of each of these persons by , Attorney-in-Fact DATE: March 27, 2001 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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. SOUTH CAROLINA ELECTRIC & GAS COMPANY By: s/N. O. Lorick N. O. Lorick, President and Chief Operating Officer Date: March 27, 2001 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. s/W. B. Timmerman W. B. Timmerman, Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer) s/K. B. Marsh K. B. Marsh, Senior Vice President - Finance and Chief Financial Officer (Principal Financial Officer) s/ M. R. Cannon M. R. Cannon, Controller (Principal Accounting Officer) Other Directors*: B. L. Amick D. M. Hagood J. A. Bennett W. H. Hipp W. B. Bookhart, Jr. L. M. Miller W. C. Burkhardt M. K. Sloan H. M. Chapman H. C. Stowe E. T. Freeman G. S. York L. M. Gressette, Jr. C. E. Zeigler, Jr. *Signed on behalf of each of these persons by , Attorney-in-Fact Date: March 27, 2001 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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED By: s/C. E. Zeigler, Jr. C. E. Zeigler, Jr., President and Chief Operating Officer Date: March 27, 2001 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. s/W. B. Timmerman W. B. Timmerman, Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer) s/K. B. Marsh K. B. Marsh, Senior Vice President - Finance and Chief Financial Officer (Principal Financial Officer) s/ M. R. Cannon M. R. Cannon, Controller (Principal Accounting Officer) Other Directors*: B. L. Amick D. M. Hagood J. A. Bennett W. H. Hipp W. B. Bookhart, Jr. L. M. Miller W. C. Burkhardt M. K. Sloan H. M. Chapman H. C. Stowe E. T. Freeman G. S. York L. M. Gressette, Jr. C. E. Zeigler, Jr. *Signed on behalf of each of these persons by , Attorney-in-Fact Date: March 27, 2001 EXHIBIT INDEX Exhibit Applicable to Form 10-K of No. SCANA SCE&G PSNC Description Agreement and Plan of Merger, dated as of February 16, 1999 as amended and restated as of May 10, 1999, by and among Public Service Company of North Carolina, Incorporated, SCANA Corporation, New Sub I, Inc. and New Sub II, Inc.(Filed as Exhibit 2.1 to Registration Statement No. 333-78227 on Form S-4 and 2.01 X X incorporated by reference herein) Restated Articles of Incorporation of SCANA as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference 3.01 X herein) Restated Articles of Incorporation of SCE&G, as adopted on December 15, 1993 (Filed as Exhibit 3.01 to Registration Statement No.333-8638 and incorporated by reference 3.02 X herein) Articles of Amendment of SCANA, dated April 27, 1995 (Filed as Exhibit 4-B to Registration 3.03 X Statement No. 33-62421 and incorporated by reference herein) Articles of Amendment of SCE&G, dated June 7, 1994 and filed June 9, 1994 (Filed as Exhibit 3.02 to Registration Statement No. 333-86387 and incorporated 3.04 X by reference herein) Articles of Amendment of SCE&G, dated November 9, 1994 (Filed as 3.05 X Exhibit 3.03 to Registration Statement No. 333-86387 and incorporated by reference herein) Articles of Amendment of SCE&G, 3.06 X dated December 9, 1994 (Filed as Exhibit 3.04 toRegistration Statement No. 333-86387 and incorporated by reference herein) Articles of Correction of SCE&G, 3.07 X dated January 17, 1995 (Filed as Exhibit 3.05 to Registration Statement No. 333-86387 and incorporated by reference herein) Articles of Amendment of SCE&G, 3.08 X dated January 13, 1995 (Filed as Exhibit 3.06 to Registration Statement No. 333-86387 and incorporated by reference herein) Articles of Amendment of SCE&G, 3.09 X dated March 30, 1995 (Filed as Exhibit 3.07 to Registration Statement No. 333-86387 and incorporated by reference herein) Articles of Correction of SCE&G Amendment to Statement filed March 30, 1995, dated December 13, 1995 (Filed as Exhibit 3.08 to Registration Statement No. 3.10 X 333-86387 and incorporated by reference herein) Articles of Amendment of SCE&G, 3.11 X dated December 13, 1995 (Filed as Exhibit 3.09 to Registration Statement No. 333-86387 and incorporated by reference herein) EXHIBIT INDEX Exhibit Applicable to Form 10-K of No. SCANA SCE&G PSNC Description Articles of Amendment of SCE&G, dated 3.12 X February 18, 1997 (Filed as Exhibit 3-L to Registration Statement No. 333-24919 and incorporated by reference herein) Articles of Amendment of SCE&G, dated 3.13 X February 21, 1997 (Filed as Exhibit 3.1 to Registration Statement No. 333-86387 and incorporated by reference herein) Articles of Amendment of SCE&G, dated April 22, 1997 (Filed as Exhibit 3.12 to 3.14 X Registration Statement No. 333-86387 and incorporated by reference herein) Articles of Amendment of SCE&G, dated April 9, 1998 (Filed as Exhibit 3.13 to 3.15 X Registration Statement No. 333-86387 and incorporated by reference herein) Articles of Amendment of SCE&G, dated May 19, 1999 (Filed as Exhibit 3.01 to 3.16 X Registration Statement No. 333-49960 and incorporated by reference herein) Articles of Amendment of SCE&G, dated August 13, 1999 (Filed as Exhibit 3.02 3.17 X to Registration Statement No. 333-49960 and incorporated by reference herein) Articles of Amendment of SCE&G, dated March 1, 2000 (Filed as Exhibit 3.03 to 3.18 X Registration Statement No. 333-49960 and incorporated by reference herein) Articles of Incorporation of PSNC (formerly New Sub II, Inc.) dated February 12, 1999 (Filed as Exhibit 3.01 to Registration Statement No. 333-45206 and incorporated by 3.19 X reference herein) Articles of Amendment of PSNC (formerly New Sub II, Inc.) as adopted on February 10, 2000 (Filed as Exhibit 3.02 to Registration Statement No. 333-45206 and 3.20 X incorporatedby reference herein) Articles of Correction of PSNC dated February 11, 2000 (Filed as Exhibit 3.03 3.21 X to Registration Statement No. 333-45206 and incorporated by reference herein) 3.22 X By-Laws of SCANA as revised and amended on December 13, 2000 (Filed herewith) 3.23 X By-Laws of SCE&G as amended and adopted on February 22, 2001 (Filed herewith) 3.24 X By-Laws of PSNC as revised and amended on February 22, 2001 (Filed herewith) Articles of Exchange of South Carolina Electric & Gas Company and SCANA Corporation (Filed as Exhibit 4-A to 4.01 X X Post-Effective Amendment No. 1 to Registration Statement No.2-90438 and incorporated by reference herein) EXHIBIT INDEX Exhibit Applicable to Form 10-K of No. SCANA SCE&G PSNC Description Indenture dated as of November 1, 1989 between SCANA Corporation and The Bank of New York, as Trustee (Filed as Exhibit 4-A to Registration No. 33-32107 and incorporated 4.02 X by reference herein) Indenture dated as of January 1, 1945, between the South Carolina Power Company and 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 (Filed as Exhibit 2-B to Registration Statement No. 2-26459 and incorporated 4.03 X X by reference herein) Fourth Supplemental Indenture dated as of April 1, 1950, to Indenture referred to in Exhibit 4.03, pursuant to which SCE&G assumed said Indenture (Exhibit 2-C to Registration Statement No. 4.04 X X 2-26459 and incorporated by reference herein) Fifth through Fifty-third Supplemental Indenture referred to in Exhibit 4.03 dated as of the dates indicated below and filed as exhibits to the Registration Statements 4.05 X X whose file numbers are set forth below and are incorporated by reference herein December 1, 1950 Exhibit 2-D to Registration No. 2-26459 July 1, 1951 Exhibit 2-E to Registration No. 2-26459 June 1, 1953 Exhibit 2-F to Registration No. 2-26459 June 1, 1955 Exhibit 2-G to Registration No. 2-26459 November 1, 1957 Exhibit 2-H to Registration No. 2-26459 September 1, 1958 Exhibit 2-I to Registration No. 2-26459 September 1, 1960 Exhibit 2-J to Registration No. 2-26459 June 1, 1961 Exhibit 2-K to Registration No. 2-26459 December 1, 1965 Exhibit 2-L to Registration No. 2-26459 June 1, 1966 Exhibit 2-M to Registration No. 2-26459 June 1, 1967 Exhibit 2-N to Registration No. 2-29693 September 1, 1968 Exhibit 4-O to Registration No. 2-31569 June 1, 1969 Exhibit 4-C to Registration No. 33-38580 December 1, 1969 Exhibit 4-O 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 2-B 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 2-A-3 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 EXHIBIT INDEX Exhibit Applicable to Form 10-K of No. SCANA SCE&G PSNC Description December 1, 1980 Exhibit 4-C to Registration No. 33-38580 April 1, 1981 Exhibit 4-D to Registration No. 33-49421 June 1, 1981 Exhibit 4-D to Registration No. 2-73321 March 1, 1982 Exhibit 4-D to Registration No. 33-49421 April 15, 1982 Exhibit 4-D to Registration No. 33-49421 May 1, 1982 Exhibit 4-D to Registration No. 33-49421 December 1, 1984 Exhibit 4-D to Registration No. 33-49421 December 1, 1985 Exhibit 4-D to Registration No. 33-49421 June 1, 1986 Exhibit 4-D to Registration No. 33-49421 February 1, 1987 Exhibit 4-D to Registration No. 33-49421 September 1, 1987 Exhibit 4-D to Registration No. 33-49421 January 1, 1989 Exhibit 4-D to Registration No. 33-49421 January 1, 1991 Exhibit 4-D to Registration No. 33-49421 February 1, 1991 Exhibit 4-D to Registration No. 33-49421 July 15, 1991 Exhibit 4-D to Registration No. 33-49421 August 15, 1991 Exhibit 4-D to Registration No. 33-49421 April 1, 1993 Exhibit 4-E to Registration No. 33-49421 July 1, 1993 Exhibit 4-D to Registration No. 33-57955 May 1, 1999 Exhibit 4.04 to Registration No. 333-86387 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 4.06 X X Statement No. 33-49421 and incorporated by reference herein) First Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421 and 4.07 X X incorporated by reference herein) Second Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955 and 4.08 X X incorporated by reference herein) Trust Agreement for SCE&G Trust I (Filed as Exhibit 4.03 to Registration 4.09 X X Statement No. 333-49960 and incorporated by reference herein) Certificate of Trust of SCE&G Trust I (Filed as Exhibit 4.04 to Registration 4.10 X X Statement No. 333-49960 and incorporated by reference herein) Junior Subordinated Indenture for SCE&G Trust I (Filed as Exhibit 4.05 4.11 X X to Registration Statement No.333-49960 and incorporated by reference herein) Guarantee Agreement for SCE&G Trust I (Filed as Exhibit 4.06 to Registration 4.12 X X Statement No. 333-49960 and incorporated by reference herein) Amended and Restated Trust Agreement for SCE&G Trust I (Filed as Exhibit 4.13 X X 4.07 to Registration Statement No. 333-49960 and incorporated by reference herein) EXHIBIT INDEX Exhibit Applicable to Form 10-K of No. SCANA SCE&G PSNC Description Debenture Purchase Agreement, dated as of September 15, 1988, with respect to $25 million of 10% Senior Debentures due October 1, 2003 (Filed as Exhibit 4.01 to 4.14 X X Registration Statement No. 333-45206 and incorporated by reference herein) Amendment to Debenture Purchase Agreement dated as of September 15, 1988, between PSNC and Southland Life Insurance Company (Filed as Exhibit 4.02 to Registration Statement No. 333-45206 and 4.15 X X incorporated by reference herein) Amendment to Debenture Purchase Agreement dated as of September 15, 1988, between PSNC and Jefferson-Pilot Life Insurance Company (Filed as Exhibit 4.03 to Registration Statement No. 333-45206 4.16 X X and incorporated by reference herein) Amendment to Debenture Purchase Agreemen dated as of September 15, 1988, between PSNC and The Franklin Life Insurance Company (Filed as Exhibit 4.04 to Registration Statement No. 333-45206 4.17 X X and incorporated by reference herein) Amendment to Debenture Purchase Agreement dated as of September 15, 1988, between PSNC and Columbus Life Insurance Company (Filed as Exhibit 4.05 to Form 10-Q for the quarter ended September 30, 2000 4.18 X X and incorporated by reference herein) Amendment to Debenture Purchase Agreement dated as of September 15, 1988, between PSNC and Salkeld & Company (Filed as Exhibit 4.06 to Form 10-Q for the quarter ended September 30, 2000 and 4.19 X X incorporated by reference herein) Amendment to Debenture Purchase Agreement dated as of September 15, 1988, between PSNC and UMB Bank (Filed as Exhibit 4.07 to Form 10-Q for the quarter ended September 30, 2000 and incorporated 4.20 X X by reference herein) Debenture Purchase Agreement, dated as of December 5, 1989, as amended, with respect to $43 million of 10% Senior Debentures due December 1, 2004 (Filed as Exhibit 4.05 to 4.21 X X Registration Statement No. 333-45206 and incorporated by reference herein) Amendment to Debenture Purchase Agreement dated as of December 5, 1989, between PSNC and The Prudential Life Insurance Company of America (Filed as Exhibit 4.06 to 4.22 X X Registration Statement No. 333-45206 and incorporated by reference herein) Debenture Purchase Agreement, dated as of June 25, 1992, with respect to $32 million of 8.75% Senior Debentures due June 30, 2012 (Filed as Exhibit 4.07 to Registration Statement No. 333-45206 4.23 X X and incorporated by reference herein) Indenture dated as of January 1, 1996 between PSNC and First Union National 4.24 X X (Filed as Exhibit 4.08 to Registration Statement No.333-45206 and incorporated by reference herein) First Supplemental Indenture dated as of 4.25 X X January 1, 1996, between PSNC and Bank of North Carolina, as Trustee (Filed as Exhibit 4.08 to Registration Statement (Filed as Exhibit 4.09 to Registration Statement No. 333-45206 and incorporated by reference herein) EXHIBIT INDEX Exhibit Applicable to Form 10-K of No. SCANA SCE&G PSNC Description Second Supplemental Indenture dated as of December 15, 1996 between PSNC and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.10 to Registration Statement No. 4.26 X X 333-45206 and incorporated by reference herein) Third Supplemental Indenture dated as of February 10, 2000 between PSNC and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.11 to 4.27 X X Registration Statement No. 333-45206 and incorporated by reference herein) Fourth Supplemental Indenture dated as of February 12, 2001 between PSNC and First Union National Bank of North 4.28 X X Carolina, as Trustee (Filed herewith) 4.29 X PSNC $150 million medium-term note issued February 16, 2001 (Filed herewith) SCANA Voluntary Deferral Plan as amended through October 21, 1997 (File as Exhibit 10.01 to Registration 10.01 X Statement No. 333-49960 and incorporated by reference herein) SCANA Supplementary Executive Retirement Plan as amended and restated effective as of October 21, 1997 (Filed as Exhibit 10.01(b) to Registration Statement No.333-86803 and incorporated 10.02 X by reference herein) SCANA Supplementary Voluntary Deferral Plan as amended and restated through October 21, 1997 (Filed as Exhibit 10.02 to Registration Statement No. 333-49960 and 10.03 X incorporated by reference herein) SCANA Key Executive Severance Benefits Plan as amended and restated effective as of October 21, 1997 (Filed as Exhibit 10.01(c) to Registration Statement No. 333-86803 10.04 X and incorporated by reference herein) SCANA Supplementary Key Executive Severance Benefits Plan effective as of December 17, 1997 (Filed as Exhibit 10.01(d) to Registration Statement No. 333-86803 and incorporated by 10.05 X reference herein) SCANA Performance Share Plan as amended and restated effective January 1, 1998 (Filed as Exhibit 10 (e) to Registration Statement No. 333-86803 and incorporated by 10.06 X reference herein) SCANA Long-Term Equity Compensation Plan dated January 2000 filed as Exhibit 4.04 to Registration Statement 10.07 X No. 333-37398 and incorporated by reference herein) SCANA Key Employee Retention Plan as amended and restated effective as of October 21, 1997 (Filed as Exhibit 10.02 to Registration Statement No. 333-49960 and 10.08 X incorporated by reference herein) Description of SCANA Whole Life Option (Filed as Exhibit 10-F to Form 10-K for the year ended December 31, 1991, under cover of Form SE, File No. 1-8809 and 10.09 X incorporated by reference herein) EXHIBIT INDEX Exhibit Applicable to Form 10-K of No. SCANA SCE&G PSNC Description 10.10 X Description of SCANA Corporation Annual Incentive Plan (Filed as Exhibit 10-G to Form 10-K for the year ended December 31, 1991, under cover of Form SE, File No.1-8809 and incorporated by reference herein) SCANA Corporation Director Compensation and Deferral Plan effective January 1, 2001(Filed as Exhibit 10.05 to Registra tion Statement No. 333-49960 and incorporated by 10.11 X reference herein) Operating Agreement of Pine Needle LNG Company, LLC dated August 8, 1995 (Filed as Exhibit 10.01 to Registration Statement No. 333-45206 and incorporate 10.12 X by reference herein) Amendment to Operating Agreement of Pin Needle LNG Company, LLC dated October 1, 1995 (Filed as Exhibit 10.02 to Registration Statement No. 333-45206 and 10.13 X incorporated by reference herein) Amended Operating Agreement of Cardinal Extension Company, LLC dated December 19, 1996 (Filed as Exhibit 10.03 to Registration Statement No. 333-45206 and 10.14 X incorporated by reference herein) Amended Construction, Operation and Maintenance Agreement by and between Cardinal Operating Company and Cardinal Extension Company, LLC dated December 19, 1996 (Filed as Exhibit 10.04 to Registration Statement No. 333-45206 and incorporated by 10.15 X reference herein) Form of Severance Agreement between PSNC and its Executive Officers (Filed as Exhibit 10.05 to Registration Statement No.333-45206 and incorporated by reference 10.16 X herein) Service Agreement between PSNC and SCANA Services, Inc., effective April 1, 2000 (Filed as Exhibit 10.06 to Registration Statement No. 333-45206 and incorporated by 10.17 X reference herein) 12.01 X X X Statement Re Computation of Ratios 23.01 X Consents of Experts and Counsel (Independent Auditors' Consent) 24.01 X X X Power of Attorney (Filed herewith)