10-K 1 ten-k.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, 2001 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, South Carolina Electric & Gas Company Series A liquidation value $25 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 (x) Public Service Company of North Carolina, Incorporated (x) The aggregate market value of voting stock held by non-affiliates of SCANA Corporation was $2.9 billion at February 28, 2002, based on a price of $27.75. 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 ---------- --------------------------- -------------------- SCANA Corporation Without Par Value 104,728,268 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 2002 Proxy Statement, dated March 22, 2002, in connection with its 2002 Annual Meeting of Shareholders, 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 PART II Item 5. Market for Registrant's Common Equity and Related Shareholder Matters...................................... 21 Item 6. Selected Financial Data.................................... 22 SCANA Corporation.......................................... 23 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Financial Statements and Supplementary Data South Carolina Electric & Gas Company....................... 80 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Financial Statements and Supplementary Data Public Service Company of North Carolina, Incorporated...... 118 Item 7. Management's Narrative Analysis of Results of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Financial Statements and Supplementary Data Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure...................................... 148 PART III Item 10. Directors and Executive Officers of the Registrants......... 148 Item 11. Executive Compensation ..................................... 153 Item 12. Security Ownership of Certain Beneficial Owners and Management ........................................... 158 Item 13. Certain Relationships and Related Transactions ............. 159 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K ................................................. 160 SIGNATURES................................................................ 164 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 C Construction BTU..................................... British Thermal Unit Circuit Court........................... South Carolina Circuit Court Consumer Advocate....................... Consumer Advocate of South Carolina DHEC.................................... South Carolina Department of Health and Environmental Control DOE..................................... United States Department of Energy DT...................................... Dekatherm (one million BTU's) DTAG.................................... Deutsche Telekom AG 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. GPSC.................................... Georgia Public Service Commission 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 Units MMCF.................................... Million Cubic Feet MW...................................... Megawatt NCUC.................................... North Carolina Utilities Commission NRC..................................... United States Nuclear Regulatory Commission PRP..................................... Potentially Responsible Party PSNC.................................... Public Service Company of North Carolina, Incorporated PUHCA................................... Public Utility Holding Company Act of 1935, as amended RTO..................................... Regional Transmission Organization Santee Cooper........................... South Carolina Public Service Authority SCANA................................... SCANA Corporation, the parent company SCE&G................................... South Carolina Electric & Gas Company SCH..................................... SCANA Communications Holdings, Inc., a subsidiary of SCI SCI..................................... SCANA Communications, Inc. SCPC.................................... South Carolina Pipeline Corporation SCPSC................................... The Public Service Commission of South Carolina SEC..................................... United States Securities and Exchange Commission SFAS.................................... Statement of Financial Accounting Standards 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 CORPORATE STRUCTURE SCANA CORPORATION A holding company owning the direct, wholly owned subsidiaries listed below SOUTH CAROLINA ELECTRIC & GAS COMPANY SCANA COMMUNICATIONS, INC. -------------------------- -------------------------- Provides fiber optic telecommunications Generates and sells electricity and gas in South Carolina, tower construction, to wholesale and retail customers; management and rental services for wireless purchases, sells and transports natural gas providers and, through a Delaware subsidiary, at retail and provides public transit invests in telecommunications companies. service in Columbia, South Carolina. SCANA ENERGY MARKETING, INC. SOUTH CAROLINA GENERATING COMPANY, INC. Markets natural gas and wholesale electricity primarily in the Southeast. Provides energy- Owns and operates Williams Station and related risk management services to producers sells electricity to SCE&G. and customers. Through its SCANA Energy division, markets natural gas in Georgia's SOUTH CAROLINA FUEL deregulated retail natural gas market. COMPANY, INC. Acquires, owns and provides financing SERVICECARE, INC. ----------------- for SCE&G's nuclear fuel, fossil fuel Provides energy-related products and and sulfur dioxide emission allowances. service contracts on home appliances. SOUTH CAROLINA PIPELINE PRIMESOUTH, INC. ------------------------ ---------------- CORPORATION Engages in power plant management and ----------- Purchases, sells and transports natural maintenance services. gas to wholesale and direct industrial customers. Owns and operates two LNG SCANA RESOURCES, INC. --------------------- plants for the liquefaction, storage and Conducts energy-related businesses and provides regasification of natural gas. energy-related services. PUBLIC SERVICE COMPANY OF SCG PIPELINE, INC. ------------------------- ------------------ NORTH CAROLINA, INCORPORATED Organized to engage in the transportation of ---------------------------- Purchases, sells, transports and distributes natural gas in Georgia and South Carolina. natural gas to retail customers, markets natural gas, refuels natural gas vehicles and SCANA SERVICES, INC. -------------------- converts gasoline-fueled vehicles to Provides administrative, management and other natural gas. services to the subsidiaries and business units within SCANA Corporation.

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. 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. 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 in liquidation. SCANA and its subsidiaries (the Company) had full-time, permanent employees as of February 28, 2002 and 2001 of 5,369 and 5,262, respectively. SCE&G was incorporated under the laws of South Carolina in 1924, and is an operating public utility. SCE&G had full-time, permanent employees as of February 28, 2002 and 2001 of 2,657 and 2,365, respectively. Prior to being acquired by SCANA in 2000, PSNC was incorporated under the laws of North Carolina in 1938. PSNC is now incorporated under the laws of South Carolina. PSNC, doing business as PSNC Energy, is an operating public utility in North Carolina with full-time, permanent employees as of February 28, 2002 and 2001 of 652 and 653, respectively. SEGMENTS OF BUSINESS SCANA neither owns nor operates any physical properties. It has 12 direct, wholly owned subsidiaries that are engaged in the functionally distinct operations described below, and an investment in ITC^DeltaCom, Inc., a telecommunications services company in the southeastern United States. SCANA also has investments in two LLCs: one owns and operates a cogeneration facility in Charleston, South Carolina and the other owns and operates a lime production facility in Charleston, South Carolina. Effective February 28, 2002 SCANA sold its interest in the lime production facility. 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, 2001, 2000 and 1999 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 13). 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. In November 2001 SCE&G signed a letter of intent to transfer the transit system to an unaffiliated regional transit authority (see discussion at Item 2, PROPERTIES - TRANSIT PROPERTIES). 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 33 of the 46 counties in South Carolina and covers more than 22,000 square miles. The total population of the counties representing the combined service area is approximately 2.6 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 manufacturing. 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. SCPC is engaged in the purchase, transmission and sale of natural gas on a wholesale basis to distribution companies and directly to industrial customers in 40 counties throughout South Carolina. SCPC 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 SCPC are primarily engaged in the manufacturing or processing of ceramics, paper, metal, food and textiles. SCPC's plan to convert from a closed system to an open access transportation only system has been postponed indefinitely due to a number of factors, including the impact of the current economic downturn and the lack of consistent customer support for the proposed plan of system conversion. PSNC is a public utility engaged primarily in purchasing, selling, transporting and distributing natural gas to approximately 379,000 residential, commercial and industrial customers. PSNC provides service to 26 of its 28 franchised counties covering approximately 12,000 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 a wholly owned, nonregulated subsidiary, 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 natural gas and wholesale electricity 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 385,000 customers (as of December 31, 2001) in Georgia's deregulated natural gas market. SCI owns and operates a 500-mile fiber optic telecommunications network in South Carolina and provides tower site construction, management and rental services in South Carolina and Georgia. SCI also owns an 800 Mhz radio service network within South Carolina, and in June 2001, agreed to subcontract the operation and maintenance of its network to Motorola, Inc. (Motorola) for the period July 1, 2001 through March 31, 2002. SCI intends to sell the network to Motorola at a purchase price in excess of its carrying value. SCH, a Delaware corporation and a wholly owned subsidiary of SCI, has investments in ITC Holding Company, Inc., ITC^DeltaCom, Inc., and Knology, Inc., which are telecommunications services companies in the southeastern United States. SCH also has an investment in Deutsche Telekom AG (DTAG), an international telecommunications carrier. This investment was received in exchange for its Powertel, Inc. (Powertel) investment owned prior to DTAG's acquisition of Powertel in May 2001. ServiceCare, Inc. (ServiceCare) is engaged primarily in providing homeowners with service contracts on their home appliances. In March 2001 ServiceCare completed the sale of its home security and alarm monitoring division. SCG Pipeline, Inc. (SCG), when operational, will provide interstate transportation services for natural gas to markets in southeastern Georgia and South Carolina. SCG will transport natural gas from interconnections with Southern Natural at Port Wentworth, Georgia, and from an import terminal owned by Southern LNG at Elba Island, near Savannah, Georgia. The endpoint of SCG's line will be at the site of SCE&G's proposed natural gas-fired generating station in Jasper County, South Carolina. In December 2001 SCG filed an application with FERC for a Certificate of Public Convenience and Necessity to acquire and build a pipeline from Elba Island, Georgia to Jasper County, South Carolina. The project has an anticipated in-service date of November 2003. Primesouth, Inc. is engaged primarily in power plant management and maintenance services. Primesouth is also involved in the operation of an alternate fuel facility owned by non-affiliates, and it receives management fees and expense reimbursement related to those activities. 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, and the Competition section of Management's Narrative Analysis of Results of Operations for PSNC. CAPITAL REQUIREMENTS The Company's cash requirements arise primarily from the operational needs of SCANA's subsidiaries, the Company's construction program 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, the Company expects 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 the Regulatory Matters captions 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 the three-year period 2002-2004, the Company expects to meet its capital requirements principally through internally generated funds (approximately 45 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 2002-2004 are as follows: ---------------------------------------------------- -------------- ------------ Type of Facilities 2004 2003 2002 ------------------ ---- ---- ---- (Millions of Dollars) South Carolina Electric & Gas Company: Electric Plant: Generation $134 $362 $328 Transmission 37 41 33 Distribution 108 101 96 Other 9 12 15 Nuclear Fuel 26 29 6 Gas 20 18 19 Common 15 23 13 Other - - 2 ---------------------------------------------------- -------------- ------------ Total SCE&G 349 586 512 PSNC 38 37 40 Other Companies Combined 44 150 131 ---------------------------------------------------- -------------- ------------ Total $431 $773 $683 ---------------------------------------------------- -------------- ------------ In October 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. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost $250 million and be completed in 2005. Any costs incurred by SCE&G are expected to be recoverable through electric rates. SCE&G is constructing 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. In October 2001 SCE&G filed with the SCPSC its siting plans to construct an 875 megawatt generation facility in Jasper County, South Carolina, to supply electricity primarily to its South Carolina customers. The facility will include three natural gas combustion-turbine generators and one steam-turbine generator. Natural gas will be provided by SCG Pipeline, Inc. Construction of the $450 million facility is expected to begin in April 2002, with commercial operation in the summer of 2004. In connection with the facility, SCE&G has signed a 250 megawatt electric supply contract with North Carolina Electric Membership Corporation for a term of at least five years beginning January 1, 2004. In addition to the capital requirements for 2002 described above, the Company, SCE&G and PSNC will require approximately $738.3 million, $27.6 million and $4.3 million, respectively, to refund and retire outstanding long-term securities and obligations in 2002 including purchase or sinking fund requirements for SCE&G's preferred stock. For the years 2003-2006, the Company has an aggregate of $1,034.3 million of long-term debt and preferred stock maturing, which includes an aggregate of $576.3 million for SCE&G, $2.2 million of purchase or sinking fund requirements for SCE&G's preferred stock and $21.4 million for PSNC. SCE&G's long-term debt maturities for the years 2003-2006 include approximately $93.8 million for sinking fund requirements, all of which may be satisfied by deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits. For a discussion of the Company's, SCE&G's and PSNC's contractual cash obligations, financing limits, financing transactions and other related information, see 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 Capital Expansion Program and Liquidity Matters section of Management's Narrative Analysis of Results of Operations for PSNC. The Company's ratios of earnings to fixed charges were 4.37, 2.47, 2.77, 3.38 and 3.27 for the years ended December 31, 2001, 2000, 1999, 1998 and 1997, respectively. For SCE&G these ratios were 3.78, 4.24, 3.71, 4.40 and 3.85 for the same periods. For PSNC these ratios were 2.54 and 3.05 for the years ended December 31, 2001 and 2000, respectively, and 3.18, 3.22 and 3.41 for its fiscal years ended September 30, 1999, 1998 and 1997, respectively. The Company has set a target ratio of debt to total capital of 50 to 52 percent. At December 31, 2001, the ratio of debt to total capital was approximately 59 percent. ELECTRIC OPERATIONS Electric Sales In 2001 residential sales of electricity accounted for 39% of electric sales revenues; commercial sales 30%; industrial sales 19%; sales for resale 3%; and all other 9%. The Company's KWH sales by classification for the years ended December 31, 2001 and 2000, excluding volumes attributable to the cumulative effect of accounting change in 2000, are presented below: KWH Sales (in millions) ---------------------------------------------------------------------------- CLASSIFICATION 2001 2000 % CHANGE ---------------------------------------------------------------------------- Residential 6,494 6,665 (3%) Commercial 6,288 6,305 - Industrial 6,347 6,665 (5%) Sales for resale 1,114 1,222 (9%) Other 534 553 (3%) -------------------------------------------------------------- Total Territorial 20,777 21,410 (3%) Negotiated Market Sales Tariff (NMST) 2,151 1,942 11% -------------------------------------------------------------- Total 22,928 23,352 (1.8%) ============================================================== Sales for resale includes sales to two municipalities and two electric cooperatives. Sales under the NMST during 2001 include sales to 39 investor-owned utilities and registered marketers, four electric cooperatives, two municipalities and four federal/state electric agencies. During 2000 sales under the NMST included sales to 36 investor-owned utilities and registered marketers, seven electric cooperatives, two municipalities and four federal/state electric agencies. The residential electric sales volume decreased for 2001 primarily as a result of milder weather. During 2001 the Company recorded a net increase of 10,143 customers, increasing its total customers to 547,388. The all-time peak demand of 4,196 MW was set on August 8, 2001. The industrial electric sales volume decreased for 2001 primarily due to the impact of an economic slowdown. For the three-year period 2002-2004, the Company's total KWH sales of electricity are projected to increase 2.4% annually. Residential KWH sales are projected to increase 1.9% annually, commercial sales 1.7%, industrial sales 2.7%, sales for resale 6.6% and other sales 0.9%. The Company's total electric customer base is projected to increase 1.4% annually. Over the same three-year period, the Company's territorial peak load (summer, in MW) is projected to increase 2% annually. The Company's goal is to maintain a reserve margin of between 12.0% and 18.0%. Electric Interconnections SCE&G purchases all of the electric generation of GENCO's Williams Station 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 Electric and Power Company, Duke Power Company, Carolina Power & Light Company, Yadkin, Incorporated and 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. (See REGULATION - FERC Orders No. 636, 888 and 2000 for further discussion of electric interconnections.) 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 1999-2001. Cost of Fuel Used ----------------------------------------- 2001 2000 1999 ---- ---- ---- Nuclear: Per MMBTU $.45 $.46 $.46 Coal: SCE&G Per ton $38.70 $37.10 $39.37 Per MMBTU 1.55 1.48 1.57 GENCO Per ton $39.23 $38.98 $41.46 Per MMBTU 1.52 1.51 1.61 Weighted Average Cost of All Fuels: Per MMBTU $1.33 $1.31 $1.32 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 1999-2001 and the estimates for the years 2002-2004. Percent of Total KWH Generated -------------------------------------------------------------- Estimated Actual -------------------------------------------------------------- 2004 2003 2002 2001 2000 1999 ---- ---- ---- ---- ---- ---- Coal 61% 66% 70% 75% 77% 73% Nuclear 20 20 20 21 18 22 Hydro 5 6 5 4 4 4 Natural Gas & Oil 14 8 5 - 1 1 ------------------ -------------------- ----------- --------- 100% 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, 2001 SCE&G had approximately a 64-day supply of coal in inventory and GENCO had approximately a 68-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 existing contracts. Contract coal is purchased from twelve suppliers located in eastern Kentucky, Tennessee, southwest Virginia and West Virginia. Contract commitments, which expire at various times through 2004, approximate 6.0 million tons annually, which is 89 percent of total expected coal purchases for 2002. Sulfur restrictions on the contract coal range from 0.75 percent to 1.5 percent. As noted above in Capital Requirements, 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 scheduled to be completed by June 2002. Also, as part of the transfer of transit assets discussed at Item 2, PROPERTIES - TRANSIT PROPERTIES, SCE&G may transfer a small hydro plant to the City of Columbia. This transfer would have minimal impact on the makeup of SCE&G's fuel supply above. The Company believes that SCE&G's and GENCO's operations comply with all existing regulations relating to the discharge of sulfur dioxide and nitrogen oxides. The Company is unaware of any more stringent sulfur content requirements for existing plants being contemplated at the state and Federal level. SCE&G has adequate supplies of uranium or enriched uranium product under contract to manufacture nuclear fuel for Summer Station through 2008. 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) 16-20 2008 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 2008 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. (See Nuclear Fuel Disposal under Environmental Matters for information regarding the contract with the DOE for disposal of spent fuel.) 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. Other Significant Events In March 2001 Summer Station returned to service. It had been taken out of service in October 2000 for a planned maintenance and refueling outage. During initial inspection activities, plant personnel discovered a small leak in a weld in a primary coolant system pipe. Repairs were completed and the integrity of the new welds was verified through extensive testing. The SCPSC has approved recovery of the cost of replacement power through SCE&G's electric fuel adjustment clause. The NRC was closely involved throughout this process and approved SCE&G's actions, as well as the restart schedule. In April 2001 SCE&G's 385 megawatt coal-fired Cope Generating Station returned to service. It had been taken out of service in January 2001 due to an electrical ground in the generator. The SCPSC has approved recovery of the cost of replacement power through SCE&G's fuel adjustment clause. SCANA and Westvaco each own a 50 percent interest in Cogen South LLC (Cogen). Cogen built and operates a cogeneration facility in North Charleston, South Carolina. On September 10, 1998 the contractor in charge of construction filed suit in Circuit Court 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 named as defendants in the suit. Cogen filed a separate suit against the contractor for delay and performance issues. The suits were combined and the contractor brought the manufacturer of the generator into the performance suit. In November 2001 a settlement was reached between all parties. Terms of the settlement are confidential, but the settlement's impact on SCANA and SCE&G's results of operations, cash flow and financial position is not material. GAS OPERATIONS For the three-year period 2002-2004, the Company's total consolidated sales of natural gas in DTs are projected to increase 1.5% annually. Residential DT sales are projected to increase 2.6% annually, commercial sales 2.7%, industrial sales 1.0% and sales for resale 0.0%. The Company's total consolidated natural gas customer base is projected to increase 2.9% annually. Gas Sales - Regulated In 2001 the Company's residential sales accounted for 40% of gas sales revenues; commercial sales 24%; industrial sales 23%; sales for resale 9%; and other 4%. During the same period, SCE&G's residential sales accounted for 44% of gas sales revenues; commercial sales 33%; and industrial sales 23%. Also during the same period, PSNC's residential sales accounted for 59% of gas sales revenues; commercial sales 27%; and industrial sales 14%. DT sales by classification for the years ended December 31, 2001 and 2000, excluding volumes associated with the cumulative effect of accounting change in 2000, are presented below:

Dekatherms Sales (in thousands) ------------------------------------------------------------------------------------------------------------------- The Company SCE&G PSNC % % % CLASSIFICATION 2001 2000 Change 2001 2000 Change 2001 2000 Change ---------------------------- --------- -------------------- --------- ---------- --------- --------- ----------- Residential 31,966 39,034 (18.1) 11,256 14,506 (22.4) 20,710 24,529 (15.6) Commercial 23,652 26,306 (10.1) 11,305 12,817 (11.8) 12,278 13,373 (8.2) Industrial 47,901 61,668 (22.3) 14,301 17,129 (16.5) 5,277 5,315 (0.7) Sales for Resale 14,827 16,931 (12.4) n/a n/a n/a n/a n/a n/a Transportation gas 28,706 31,675 (9.4) 2,461 2,085 18.0 25,719 29,413 (12.6) ------ ------ ----- -- ----- ------ ------ Total 147,052 175,614 (16.3) 39,323 46,537 (15.5) 63,984 72,630 (11.9) ============================ ========= ==================== ========= ========== ========= ========= ===========

The Company's DT sales noted above include SCPC sales of 84,840 DTs and 103,815 DTs, for 2001 and 2000, respectively (including transactions with affiliates). The Company's and SCE&G's gas sales volume decreased for 2001 primarily as a result of the slowing economy. During 2001 the Company recorded a net increase of approximately 9,200 customers, increasing its total customers to approximately 646,200. SCE&G recorded a net increase of approximately 800 gas customers, increasing its total customers to approximately 267,200. PSNC recorded a net increase of approximately 8,700 customers, increasing its total customers to approximately 378,900. The demand for gas is affected by the weather, the price relationship between gas and alternate fuels and other factors. SCPC, 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. 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, Supply and Curtailment Plans South Carolina SCPC purchases natural gas under contracts with producers and marketers in both the spot and long-term markets. 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 SCPC 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 SCPC's system as capacity is available for interruptible transportation. SCE&G, under contract with SCPC, is entitled to receive a daily contract demand of 276,495 dekatherms. The contract allows SCE&G to receive amounts in excess of this demand based on availability. During 2001 SCPC's average cost per MCF of natural gas purchased for resale, including firm service demand charges, was $5.47 compared to $4.39 during 2000. SCE&G's average cost per MCF was $6.91 and $5.35 during 2001 and 2000, respectively. These increases reflect average natural gas prices during the three months ended March 31, 2001 that were approximately $4.68 (for SCPC) and $4.58 (for SCE&G) higher than the three months ended March 31, 2000. SCPC 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 SCPSC. Any gains or losses associated with that hedging activity are accounted for in SCPC'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, SCPC 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 1,689 MMCF of gas were in storage at December 31, 2001. On peak days the LNG plants can regasify up to 150 MMCF per day. Additionally, SCPC had contracted for 6,447 MMCF of natural gas storage space. Approximately 5,393 MMCF of gas were in storage on December 31, 2001. The SCPSC has established allocation priorities applicable to the firm and interruptible capacities of SCPC. These curtailment plan priorities apply to the resale distribution customers of SCPC, including SCE&G. North Carolina PSNC 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 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 has submitted non-binding nominations for firm transportation service on three proposed pipeline projects to meet incremental capacity requirements beginning in 2003. At December 31, 2001 evaluation and final determination regarding subscription to these projects were ongoing. During 2001 PSNC's average cost per DT of natural gas purchased for resale, including firm service demand charges, was $6.50 compared to $5.63 during 2000. This increase reflects average natural gas prices during the three months ended March 31, 2001 that were approximately $4.57 per DT higher than the three months ended March 31, 2000. To meet the requirements of its high priority natural gas customers during periods of maximum demand, PSNC supplements its supplies of natural gas with underground natural gas storage services and 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'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 911 MMCF were in storage at December 31, 2001. LNG storage service agreements with Transco, Cove Point LNG and Pine Needle LNG provide for approximately 1,266 MMCF of storage space, all of which was filled at December 31, 2001. 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. Gas Marketing - Nonregulated Energy Marketing's activities are primarily focused in the Southeast, where it 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 385,000 customers (as of December 31, 2001) in Georgia's deregulated natural gas market. 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. 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 SCPSC as to retail electric, gas and transit rates, service, accounting, issuance of securities (other than short-term promissory notes) and other matters. PSNC is subject to the jurisdiction of the NCUC as to gas rates, service, issuance of securities (other than notes with a maturity of two years or less or renewals of notes with a maturity of six years or less), accounting and other matters. SCPC is subject to the jurisdiction of the SCPSC as to gas rates, 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 the Liquidity and Capital Resources section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.) 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 Columbia 2000 Parr Shoals 2020 Saluda 2007 Stevens Creek 2025 Fairfield Pumped Storage 2020 Neal Shoals 2036 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. SCE&G expects to transfer the Columbia Project to the City of Columbia in 2002 in connection with SCE&G's proposed transfer of its transit system to an unaffiliated regional transit authority. See ITEM 2, PROPERTIES. 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. FERC Orders No. 636, 888 and 2000 The Company's regulated business operations were impacted by FERC Orders No. 636, 888 and 2000. 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. As already noted, Order No. 2000 required utilities which operate electric transmission systems to submit plans for the possible formation of RTOs. In March 2001 FERC gave provisional approval to SCE&G and two other southeastern electric utilities to establish GridSouth Transco, LLC (GridSouth) as an independent regional transmission company, responsible for operating and planning the utilities' combined transmission systems. In July 2001 FERC expressed its desire that utilities throughout the United States combine their transmission systems to create four large independent regional operators, one each in the Northeast, Southeast, Midwest and West. Accordingly, FERC ordered mediation talks to take place between the utilities forming GridSouth and certain groups that had proposed other RTOs. These talks were mediated by an administrative law judge, who issued her nonbinding mediation report to FERC in September 2001. The report made recommendations related to the formation of a Southeast regional RTO. While FERC has not acted on the mediation report, and the timing or impact of future FERC orders related to RTOs cannot be predicted, SCE&G expects to be reimbursed or to otherwise recover costs it has incurred in connection with RTO formation. 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 SCPSC and NCUC, respectively, and are in effect for bills rendered during the period 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 SCPSC 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 2001 annual review of the fuel cost component of electric rates, the SCPSC increased the fuel cost component of the electric rate 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 SCPSC 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. PSNC 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 benchmark 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. SCPC's cost of gas is calculated and recovered each month based on actual costs incurred using a method approved by the SCPSC. A review of costs and calculations is performed by the SCPSC in its annual review of the purchased gas adjustments and gas purchasing policies. 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, SCE&G and PSNC, 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 1999 through 2001, the Company's capital expenditures for environmental control totaled approximately $79.7 million (including approximately $74.8 million for SCE&G). This was in addition to expenditures included in "Other operation and maintenance" expenses, which were approximately $23.0 million, $19.6 million, and $18.2 million during 2001, 2000 and 1999, respectively (including approximately $17.0 million, $16.6 million and $15.0 million for SCE&G during 2001, 2000 and 1999, respectively). It is not possible to estimate all future costs for environmental purposes, but forecasts for capitalized environmental expenditures for the Company are $78.7 million for 2002 and $177.8 million for the four-year period 2003 through 2006 (including $69.5 million for 2002 and $92.3 million for the four-year period 2003 through 2006 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 to address the issue of NOx pollution. While not final, South Carolina has proposed NOx reductions that would require the Company to install pollution control equipment to reduce its NOx emission. Capital expenditures required to comply with the NOx reductions are included in the cost figures above. 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 in 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 Matters in the Liquidity and Capital Resources section of Management's Discussion and Analysis of Financial Condition and Results of Operations for the Company. ITEM 2. PROPERTIES SCANA owns no significant property other than the capital stock of each of its subsidiaries and certain investments in ITC^DeltaCom preferred stock. 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, in liquidation. 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. Effective February 28, 2002 SCANA sold its interest in the lime production facility. 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 PROPERTIES 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 ----- Urquhart (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 (5) 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 (one-third owned by Santee Cooper). (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. (5) In connection with the proposed transfer of the transit system to an unaffiliated regional transit authority as discussed below, this facility is expected to be transferred to the City of Columbia in 2002. * 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 451 substations having an aggregate transformer capacity of 22,673,584 KVA. The transmission system consists of 3,170 miles of lines and the distribution system consists of 16,965 pole miles of overhead lines and 4,099 trench miles of underground lines. NATURAL GAS PROPERTIES SCE&G's natural gas system consists of approximately 12,793 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 325 MMCF of natural gas. SCPC's natural gas system consists of approximately 1,945 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. SCPC 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 natural gas system consists of approximately 810 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 7,425 miles of distribution mains and related service facilities. PSNC owns one LNG plant with storage capacity of 1,000 MMCF and the capacity to liquefy approximately 100 MMCF per day. 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 PROPERTIES 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, and in November 2001, signed a letter of intent to negotiate transferring the transit system to an unaffiliated regional transit authority. As part of the negotiations, SCE&G expects to transfer a small hydro plant to the City of Columbia in 2002. Management is uncertain as to what the costs associated with the disposition of the transit system will be or when the disposition will be finalized. ITEM 3. LEGAL PROCEEDINGS The Company is subject to claims and assertions in the normal conduct of its operations. 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 11 for PSNC). ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not Applicable PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS COMMON STOCK INFORMATION - SCANA Corporation ------------------ ------------------------------------------------- ------------------------------------------------ 2001 2000 ------------------ ----------- ----------- ------------- ----------- ----------- ------------ ---------- ------------ 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr. 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr. ------------------ ----------- ----------- ------------- ----------- ----------- ------------ ---------- ------------ Price Range: (a) High 27.99 28.49 29.03 30.00 31.13 30.94 26.88 29.00 Low 25.00 24.25 26.61 24.92 25.75 24.38 22.81 22.00 ------------------ ------------ ----------- ----------- ------------ ----------- ----------- ------------ ----------- (a) As reported on the New York Stock Exchange Composite Listing. ------------------------------ ------------------ ------------------ ----------- ------------------ ----------------- DIVIDENDS PER SHARE 2001 2000 ------------------------------ ------------------ ------------------ ------------------ ----------------- ----------- Amount Date Declared Date Paid Amount Date Declared Date Paid ------ ------------- --------- ------ ------------- --------- First Quarter .30 February 22, 2001 April 1, 2001 .2875 February 22, 2000 April 1, 2000 Second Quarter .30 May 3, 2001 July 1, 2001 .2875 April 27, 2000 July 1, 2000 Third Quarter .30 August 2, 2001 October 1, 2001 .2875 August 16, 2000 October 1, 2000 Fourth Quarter .30 November 1, 2001 January 1, 2002 .2875 October 17, 2000 January 1, 2001 ----------------- ------------ ------------------ ------------------ ----------- ------------------ -----------------

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, 2002 was 104,728,268. The number of common shareholders of record at February 28, 2002 was 41,677. All of SCE&G and PSNC's common stock is owned by SCANA and has no market. During 2001 and 2000 SCE&G paid $157.3 million and $130.8 million, respectively, in cash dividends to SCANA. During 2001 and 2000 PSNC paid $18.3 million and $19.0 million, respectively, in cash dividends to SCANA.

SECURITIES RATINGS (As of February 28, 2002) 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 ------ ----- ----- ----- ----- ---------- ----- --------- ----- Moody's A3 A1 A1 a2 a2 P-1 A2 P-1 Standard & A- A A BBB+ BBB+ A-1 A A-1 Poors Fitch Ratings A- A+ A+ A A F-1 n/a n/a ---------------- ----------- ----------- ----------- ---------- ----------- ------------ ------------- -------------

Further reference regarding these debt and equity securities is made to the Notes to Consolidated Financial Statements appearing in Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for SCANA (Notes 6, 8 and 10), SCE&G (Notes 5, 7 and 9) and PSNC (Notes 7 and 8). 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, 2001 approximately $36.8 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 ------------------------------------------------------ ---------- ----------- ------------ ---------- --------- As of and for the Year Ended December 31, 2001 2000(1) 1999 1998 1997 ------------------------------------------------------ ---------- ----------- ------------ ---------- ---------- (Millions of Dollars, Except Statistics and Per Share Statement of Income Data------------------------------------------ Operating Revenues $3,451 $3,433 $2,078 $2,106 $1,725 Operating Income 528 554 353 470 425 Other Income 550 44 90 19 41 Income Before Cumulative Effect of Accounting 539 221 179 223 221 Change-------------- Net Income 539 250 179 223 221 ------- Balance Sheet Data------- Utility Plant, Net $5,263 $4,949 $3,851 $3,787 $3,648 Total Assets 7,822 7,427 6,011 5,281 4,932 Capitalization: Common Equity 2,194 2,032 2,099 1,746 1,788 Preferred Stock (Not Subject to Purchase or 106 106 106 106 106 Sinking Funds) Preferred Stock, Net (Subject to Purchase or 10 10 11 11 12 Sinking Funds) 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 50 50 50 50 50 2027 Long-term Debt, Net 2,646 2,850 1,563 1,623 1,566 --------------------------------------------------- ---------- ----------- ------------ ---------- ---------- --------------------------------------------------- ---------- ----------- ------------ ---------- Total Capitalization $5,006 $5,048 $3,829 $3,536 $3,522 =================================================== ========== =========== ============ ========== ========== Common Stock Data Weighted Average Number of Common Shares Outstanding (Millions) 104.7 104.5 103.6 105.3 107.1 Basic and Diluted Earnings Per Share $5.15 $2.40 $1.73 $2.12 $2.06 Dividends Declared Per Share of Common Stock $1.20 $1.15 $1.32 $1.54 $1.51 Other Statistics (2) Electric: Customers (Year-end) 547,388 537,253 523,552 517,447 503,905 Total Sales (Million Kwh) 22,928 23,352 21,744 21,203 18,852 Residential: Average Annual Use Per Customer (Kwh) 14,196 14,596 14,011 14,481 13,214 Average Annual Rate Per Kwh $.0805 $.0787 $.0787 $.0801 $.0799 Generating Capability - Net Mw (Year-end) 4,520 4,544 4,483 4,387 4,350 Territorial Peak Demand - Net Mw 4,196 4,211 4,158 3,935 3,734 Regulated Gas: Customers (Year-end) 646,230 637,018 260,456 257,051 252,797 Sales, Excluding Transportation (Thousand 1,183,463 1,389,975 1,013,083 1,002,952 945,289 Therms) Residential: Average Annual Use Per Customer (Therms) 616 644 507 521 531 Average Annual Rate Per Therm $1.17 $1.08 $.86 $.86 $.86 Nonregulated Gas: Retail Customers (Year-end) 385,581 431,814 430,950 78,091 N/a Firm Customer Deliveries (Thousand Therms) 359,602 431,115 229,660 4,692 N/a Interruptible Customer Deliveries (Thousand 407,188 306,099 188,828 2,167,931 782,248 Therms)(3) --------------------------------------------------- ---------- ----------- ------------ ---------- ---------- SCE&G --- --- ---------- ---------- ---------- ---------- -------- 2001 2000 1999 1998 1997 --- --- ---------- ---------- ---------- ---------- -------- Amounts)------------------------------------------ $1,715 $1,669 $1,465 $1,450 $1,337----- 428 457 393 448 387----- 30 16 12 9 5---- 222 231 189 227 195--- 222 253 189 227 195-- $3,891 $3,615 $3,501 $3,432 $3,310- 4,962 4,671 4,404 4,246 4,054 1,750 1,657 1,558 1,499 1,447 106 106 106 106 106 10 10 11 11 12 50 50 50 50 50 1,412 1,267 1,121 1,206 1,262 --------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- $3,328 $3,090 $2,846 $2,872 $2,877 ========== ========== ========== ========== ========== N/a N/a N/a N/a N/a N/a N/a N/a N/a N/a N/a N/a N/a N/a N/a 547,411 537,286 523,581 517,472 503,930 22,928 23,353 21,746 21,204 18,853 14,196 14,596 14,011 14,481 13,214 $.0805 $.0787 $.0787 $.0801 $.0799 3,905 3,929 3,883 3,807 3,790 4,196 4,211 4,158 3,935 3,734 267,206 266,451 260,348 256,843 252,589 368,632 444,521 414, 800 405,249 381,726 509 507 521 531 563 $1.21 $.95 $.86 $.86 $.86 N/a N/a N/a N/a N/a N/a N/a N/a N/a N/a N/a N/a N/a N/a N/a ---------- ---------- ---------- ---------- ----------

(1) Reflects acquisition of PSNC effective January 1, 2000. (2) Other Statistics for 2000 exclude the effect of the change in accounting for unbilled revenues, where applicable. (3) Interruptible customer deliveries for 1998 and 1997 include volumes from the Houston office of Energy Marketing, which was closed in 1999. SCANA CORPORATION Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................ 24 Item 7A. Quantitative and Qualitative Disclosures About Market Risk... 43 Item 8. Financial Statements and Supplementary Data.................. 46 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 and nonutility 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, (12) volatility in commodity natural gas markets and (13) 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 Electric Operations After the energy supply and pricing problems experienced in California in 2000 and 2001, the efforts to restructure electric markets at the state level have slowed considerably. Many states that had considered legislation to restructure the electric industry have stopped such efforts or are proceeding more slowly. In South Carolina electric restructuring efforts remain stalled, and consideration of electric restructuring legislation is unlikely in 2002. Further, while several companies have announced their intent to site merchant generating plants in the Company's service territory, economic events, environmental concerns and other factors have slowed those efforts. Legislation or regulatory action at the Federal level, particularly as part of a larger energy policy initiative, may be considered in 2002. 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. 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 increased significantly, and SCE&G has executed 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. Gas Distribution Effective January 1, 2000 SCANA completed its acquisition of PSNC. The acquisition 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. Gas Transmission SCG, when operational, will provide interstate transportation services for natural gas to markets in southeastern Georgia and South Carolina. SCG will transport natural gas from interconnections with Southern Natural at Port Wentworth, Georgia, and from an import terminal owned by Southern LNG at Elba Island, near Savannah, Georgia. The endpoint of SCG's line will be at the site of SCE&G's proposed natural gas-fired generating station in Jasper County, South Carolina. In December 2001 SCG filed an application with FERC for a Certificate of Public Convenience and Necessity to acquire and build a pipeline from Elba Island, Georgia to Jasper County, South Carolina. The project has an anticipated in-service date of November 2003. SCPC's plan to convert from a closed system to an open-access transportation-only system has been postponed indefinitely due to a number of factors, including the impact of the current economic downturn and the lack of consistent customer support for the proposed plan of system conversion. Retail Gas Marketing SCANA Energy, the Company's nonregulated retail gas division in Georgia, has maintained its position as the second largest marketer in Georgia, with an approximate 27 percent market share. Due to record high natural gas prices and cold winter temperatures, the Georgia Public Service Commission (GPSC) adopted emergency rules which prohibited gas marketers from disconnecting service to residential customers for non-payment from mid-January through March 2001. Customers were also permitted to switch marketers without first paying outstanding balances owed to their previous provider. As a result of this action, SCANA Energy increased its allowance for uncollectible accounts in the first quarter of 2001 and, to the extent permitted by other GPSC rules, has implemented more stringent credit policies. Since that time, the GPSC has remained extremely active in its review and oversight of the natural gas marketplace. In the summer of 2001 the GPSC placed restrictions on the length of time that customer deposits may be held by marketers and also called for other changes in the ways that marketers interact with their customers. Further, in September, Georgia's Governor called for the formation of a task force to study the impact of natural gas deregulation. In January 2002 that task force reported its recommendations regarding further restructuring. The Georgia legislature is currently considering bills which, if enacted, would allow electric membership cooperatives to seek certification to market natural gas and provide for the establishment of a regulated alternative supplier of gas services. These actions raise concern as to the level of additional restrictions which may be placed on marketers, including SCANA Energy, and heighten the risks of SCANA Energy's business efforts in that market. SCANA Energy and SCANA's other natural gas distribution, transmission and marketing segments maintain gas inventory and also utilize forward contracts and financial instruments, including futures contracts, to manage their exposure to fluctuating commodity natural gas prices. (See Note 12 of Notes to Consolidated Financial Statements.) As a part of this risk management process, a portion of SCANA's projected natural gas needs has been purchased or otherwise placed under contract. This factor and others (e.g., the level of bad debts experienced) are, in the aggregate, used to establish retail pricing levels at SCANA Energy. As a result of the potential regulatory actions discussed above and other downward pricing pressures inherent in the competitive market, SCANA Energy may be unable to sustain its current levels of customers and/or pricing, thereby reducing expected margins and profitability. LIQUIDITY AND CAPITAL RESOURCES The Company's cash requirements arise primarily from the operational needs of SCANA subsidiaries, the Company's construction program, the activities or investments of SCANA's 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, the Company expects 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. The estimated primary cash requirements for 2002 and the actual primary cash requirements for 2001, excluding requirements for non-nuclear fuel purchases, short-term borrowings and dividends, are as follows: Millions of Dollars 2002 2001 ---------------------------------------------------------------------- --------- Property additions and construction expenditures, net of AFC $677 $544 Nuclear fuel expenditures 6 4 Investments 18 46 Maturing obligations, redemptions and sinking and purchase fund requirements 714 317 --------------------------------------------------------------------------- ---- Total $1,415 $911 =========================================================================== ==== Approximately 41 percent of total cash requirements was provided from internal sources in 2001 as compared to 39 percent in 2000. For the years 2003-2006 the Company has an aggregate of $1,034.3 million of long-term debt and preferred stock maturing, which includes an aggregate of $576.3 million for SCE&G, $2.2 million of purchase or sinking fund requirements for SCE&G's preferred stock and $21.4 million for PSNC. SCE&G's long-term debt maturities for the years 2003-2006 include approximately $93.8 million for sinking fund requirements all of which may be satisfied by deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits. These obligations and other commitments are tabulated below. Contractual Cash Obligations Less than After December 31, 2001 Total 1year 1-3 years 4-5 years 5 years ----------------- ----- ----- --------- --------- ------- (Millions of Dollars) Long-term and short-term debt (including interest) $5,364 $1,071 $1,217 $399 $2,677 Preferred stock sinking funds 11 1 2 1 7 Capital leases 3 1 2 - - Operating leases 90 17 37 19 17 Other commercial commitments 1,025 509 305 30 181 Included in other commercial commitments are estimated obligations under forward contracts for natural gas purchases. Certain of these contracts relate to regulated gas businesses; therefore, the effects of such contracts on gas costs are reflected in gas rates. The forward contracts for natural gas purchases include customary "make-whole" or default provisions, but are not considered to be "take-or-pay" contracts. In addition to these commercial commitments, the Company is party to certain New York Mercantile Exchange (NYMEX) futures contracts for which any unfavorable market movements have already been funded in cash. These derivatives are accounted for as cash flow hedges under Statement of Financial Accounting Standards (SFAS) No. 133 and their effects are reflected within other comprehensive income until such time as underlying transactions occur. The Company anticipates that its contractual cash obligations will be met through internally generated funds 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 foreseeable future. Financing Limits and Related Matters The Company's issuance of various securities including long-term and short-term debt is subject to customary approval or authorization by state and Federal regulatory bodies including state public service commissions, the SEC and FERC. The following paragraphs describe the financing programs currently utilized by the Company. SCANA Corporation SCANA has in effect a medium-term note program for the issuance from time to time of unsecured medium-term debt securities. While issuance of these securities requires customary approvals discussed above, the Indenture under which they are issued contains no specific limit on the amount which may be issued. At December 31, 2001 SCANA had $163 million of unused authorized lines of credit, of which $50 million was committed and the remainder was uncommitted. Amounts outstanding under SCANA's lines of credit totaled $0 and $85 million at December 31, 2001 and 2000, respectively. South Carolina Electric & Gas Company SCE&G is subject to the jurisdiction of the SCPSC as to retail electric, gas and transit rates, service, accounting, issuance of securities (other than short-term promissory notes) and other matters. 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, 2001 the Bond Ratio was 5.77. The Old Mortgage allows the issuance of Class A Bonds up to an additional principal amount equal to (i) 70 percent of unfunded net property additions (which unfunded net property additions totaled approximately $1,759 million at December 31, 2001), (ii) retirements of Class A Bonds (which retirement credits totaled $44.9 million at December 31, 2001), and (iii) cash on deposit with the Trustee. SCE&G is also 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. 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, 2001 the New Bond Ratio was 5.71. SCE&G's Restated Articles of Incorporation prohibit issuance of additional shares of preferred stock without the consent of the preferred shareholders 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 on all shares of preferred stock outstanding immediately after the proposed issue (Preferred Stock Ratio). For the year ended December 31, 2001, the Preferred Stock Ratio was 1.83. 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. At December 31, 2001 SCE&G had $250 million of unused authorized lines of credit under a credit agreement supporting the issuance of commercial paper. SCE&G's commercial paper outstanding at December 31, 2001 and 2000 was $114.7 million and $117.5 million, respectively. In addition, Fuel Company has a credit agreement for a maximum of $125 million with the full amount available at December 31, 2001. 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, 2001 and 2000 was $50.1 million and $70.2 million, respectively. This commercial paper and amounts outstanding under the revolving credit agreement, if any, are guaranteed by SCE&G. Public Service Company of North Carolina, Incorporated PSNC has in effect a medium-term note program for the issuance from time to time of unsecured medium-term debt securities. At December 31, 2001 PSNC had $125 million unused authorized lines of credit under a credit agreement supporting the issuance of commercial paper. PSNC had no commercial paper outstanding on December 31, 2001. PSNC's commercial paper outstanding at December 31, 2000 was $125 million. Financing Transactions and Other Information The following financing transactions have occurred since January 1, 2001: o On January 24, 2001 SCANA issued $202 million of 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 of 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. The proceeds were used to reduce short-term debt and for general corporate purposes. o On May 9, 2001 SCANA issued $300 million of medium-term notes maturing May 15, 2011 and bearing a fixed interest rate of 6.875 percent. SCANA also entered into an interest rate swap agreement, designated as a fair value hedge, to pay variable rate and receive fixed rate interest payments. The proceeds from the issuance of the medium-term notes were used to refinance $300 million of bank notes originally issued to finance SCANA's acquisition of PSNC. The swap agreement was terminated and replaced with another swap agreement to pay variable rate and receive fixed rate interest payments, also designated as a fair value hedge, in August 2001. Approximately $6.5 million received upon the original swap's termination is being amortized over the term of the associated debt. o On December 19, 2001 PSNC entered into two interest rate swap agreements to pay variable rate and receive fixed rate interest payments on a combined notional amount of $44.9 million. These swaps were designated as fair value hedges of PSNC's $12.9 million, 10 percent senior debentures due 2004 and $32.0 million, 8.75 percent senior debentures due 2012. o On January 31, 2002 SCANA issued $250 million of medium-term notes maturing February 1, 2012 and bearing a fixed interest rate of 6.25 percent. Also on January 31, 2002 SCANA issued $150 million of two-year floating rate notes maturing on February 1, 2004. The interest rate on the floating rate notes is reset quarterly based on three-month LIBOR plus 62.5 basis points. Proceeds from these issuances were used to refinance $400 million of two-year floating rate notes that matured on February 8, 2002, which had been issued to finance SCANA's acquisition of PSNC. o On January 31, 2002 SCE&G issued $300 million of first mortgage bonds having an annual interest rate of 6.625 percent and maturing February 1, 2032. The proceeds from the sale of these bonds were used to reduce short-term debt primarily incurred as a result of SCE&G's construction program and to redeem its First and Refunding Mortgage Bonds, 8 7/8 percent Series due August 15, 2021. 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. The more recent borrowings were necessitated by the cash requirements of the construction program, including the projects described below. SCE&G is constructing 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. In October 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. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost $250 million and be completed in 2005. Any costs incurred by SCE&G are expected to be recoverable through electric rates. In October 2001 SCE&G filed with the SCPSC its siting plans to construct an 875 megawatt generation facility in Jasper County, South Carolina, to supply electricity to its South Carolina customers. The facility will include three natural gas combustion-turbine generators and one steam-turbine generator. Construction of the $450 million facility is expected to begin in April 2002, with commercial operation in the summer of 2004. In connection with the facility, SCE&G has signed a 250 megawatt electric supply contract with North Carolina Electric Membership Corporation for a term of at least nine years beginning January 1, 2004. ENVIRONMENTAL MATTERS Electric Operations The Clean Air Act Amendments of 1990 (CAA) required electric utilities to reduce emissions of sulfur dioxide and nitrogen oxides (NOx) substantially by the year 2000. The Company's compliance with these reductions has been accomplished. The EPA has indicated that it will propose regulations by December 2003 for stricter limits on mercury and other toxic pollutants generated by coal-fired plants. SCE&G and GENCO currently estimate that air emissions control equipment will require capital expenditures of $165 million over the 2002-2006 period to retrofit existing facilities, with increased operation and maintenance costs of approximately $1.8 million per year. To meet compliance requirements for the years 2007 through 2011, the Company anticipates additional capital expenditures of approximately $82 million. In October 1998 the EPA issued a final rule requiring 22 states, including South Carolina, to modify their state implementation plans to address the issue of NOx pollution. While not final, South Carolina has proposed NOx reductions that would require the Company to install pollution control equipment to reduce its NOx emissions. Capital expenditures will be required to comply with the NOx reductions and they are included in the cost figures above. The EPA has undertaken an aggressive enforcement initiative against the industry and the Department of Justice 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. The basis for these suits is the assertion 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. The regulations under the CAA provide certain exemptions to the definition of "major modifications," including 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 of these activities is covered by the exemption for routine repair, replacement and maintenance. The regulations also provide an exemption for an increase in emissions resulting from increased hours of operation or production rate and from demand growth. It is possible that the EPA will commence enforcement actions against SCE&G, and the EPA has the authority to seek penalties at the rate of up to $27,500 per day for each violation. The EPA also could seek installation of BACT (or equivalent) at the three plants. The Company believes that any assertions relative to the Company's and SCE&G's compliance with the CAA would be without merit. However, if successful, such assertions could have a material adverse effect on the Company's financial position, cash flows and results of operations. The Federal Clean Water Act, as amended, provides for the imposition of effluent limitations that require treatment for wastewater discharges. 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. Gas Distribution The Company maintains an environmental assessment program to identify and evaluate 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 to regulated operations and are deferred and amortized with recovery provided through rates. Deferred amounts for SCE&G, net of amounts previously recovered through rates and insurance settlements, totaled $24.4 million and $20.2 million at December 31, 2001 and 2000, respectively. The deferral includes the estimated costs associated with the following matters. o In September 1992 the EPA notified SCE&G, among others, of its 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 various industrial operations, including one of SCE&G's decommissioned MGPs. Field work at the site began in November 1993 and has required the submission of several investigative reports and the implementation of several work plans. In September 2000 SCE&G was notified by the South Carolina Department of Health and Environmental Control (DHEC) that benzene contamination was detected in the intermediate aquifer on surrounding properties of the Calhoun Park area site. The EPA required that SCE&G conduct a focused Remedial Investigation/Feasibility Study on the intermediate aquifer, which was completed in June 2001. The EPA expects to issue a Record of Decision dealing with the intermediate aquifer and sediments in June 2002. SCE&G anticipates that major remediation activities will be completed in 2003, with certain monitoring activities continuing until 2007. As of December 31, 2001, SCE&G has spent approximately $15.8 million to remediate the Calhoun Park area site. Total remediation costs are estimated to be $21.9 million. o SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by DHEC. SCE&G is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. SCE&G anticipates that major remediation activities for these three sites will be completed between 2003-2005. SCE&G has spent approximately $2.0 million related to these sites, and expects to incur an additional $6.0 million. 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 two sites 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. PSNC estimates that the cost to remediate the sites would range between $11.3 million and $21.9 million. 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. At December 31, 2001 PSNC has recorded a liability and associated regulatory asset of $9.1 million, which reflects the minimum amount of the range, net of shared cost recovery expected from other PRPs and expenditures for work completed. Amounts incurred to date are approximately $1.1 million. Management believes that all MGP cleanup costs incurred will be recoverable through gas rates. REGULATORY MATTERS - STATE 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 $100 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities of approximately $142 million and $76 million, respectively, on its balance sheet at December 31, 2001. The Company's generation assets would be 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, 2001 the Company's net investment in fossil/hydro and nuclear generation assets was $1,559.7 million and $572.9 million, respectively. South Carolina Electric & Gas Company SCE&G is subject to the jurisdiction of the SCPSC as to retail electric, gas and transit rates, service, accounting, issuance of securities (other than short-term promissory notes) and other matters. Electric On April 24, 2001 the SCPSC approved SCE&G's request to increase the fuel component of rates charged to electric customers from 1.330 cents per kilowatt-hour to 1.579 cents per kilowatt-hour. The increase reflects higher fuel costs projected for the period May 2001 through April 2002. The increase also provides recovery over a two-year period of under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of SCE&G's base load generating plants in winter 2000-2001. The new rates were effective as of the first billing cycle in May 2001. On September 14, 1999 the SCPSC 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 SCPSC 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 SCPSC. 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, 2001, no accelerated depreciation has been recorded. The accelerated capital recovery plan will be accomplished through existing customer rates. On January 9, 1996 the SCPSC authorized a return on common equity of 12.0 percent. The SCPSC 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 SCPSC approved accelerated amortization 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, which enabled SCE&G to recover the balances as of the end of the year 2000. Gas SCE&G's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by SCE&G. SCE&G's cost of gas component in effect during the years ended December 31, 2001 and 2000 was as follows: Rate Per Therm Effective Date Rate Per Therm Effective Date $.993 January-February 2001 $.543 January-July 2000 $.793 March-October 2001 $.688 August-October 2000 $.596 November-December 2001 $.782 November-December 2000 On July 5, 2000 the SCPSC 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. The retroactive effect was recorded in the second quarter of 2000. In 1994 the SCPSC 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 October 2001, as a result of the annual review, the SCPSC approved SCE&G's request to increase the billing surcharge from 1.1 cents per therm to 3.0 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2005, of the balance remaining at December 31, 2001 of $24.4 million. Transit In September 1992 the SCPSC 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 SCPSC also required $.40 fares for low income customers and denied SCE&G's request for certain bus route and schedule changes. The new rates were placed into effect in October 1992. After several appeals and petitions for reconsideration to the Circuit Court and the Supreme Court by the various parties, on September 27, 2000 the SCPSC issued an order granting certain relief requested by SCE&G. On September 29, 2000 the Consumer Advocate filed a motion with the SCPSC for a stay of this order. On October 3, 2000 the SCPSC 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 SCPSC's order granting relief. The Circuit Court has held in abeyance any appellate review pending the outcome of current negotiations on the transfer of the transit system from SCE&G to an unaffiliated regional transit authority. Public Service Company of North Carolina, Incorporated 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 with a maturity of six years or less), accounting and other matters. PSNC's rates are established using a benchmark 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. PSNC's benchmark cost of gas in effect during the years ended December 2001 and 2000 was as follows: Rate Per Therm Effective Date Rate Per Therm Effective Date $.690 January 2001 $.300 January 2000 $.750 February-March 2001 $.265 February-May 2000 $.650 April-August 2001 $.350 June 2000 $.500 September-October 2001 $.450 July-September 2000 $.350 November-December 2001 $.490 October-December 2000 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. This mechanism allows PSNC to collect from its customers amounts approximating the amounts paid for natural gas. 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. On June 29, 2000 the NCUC approved PSNC's requests for 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. The Madison County portion of the project was completed at a cost of approximately $5.8 million, and customers began receiving service in July 2001. On December 7, 1999 the NCUC issued an order approving SCANA's acquisition of PSNC. As specified in the NCUC order, PSNC reduced its rates by approximately $1 million in each of August 2000 and August 2001, and agreed to a moratorium on general rate cases until August 2005. 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. Most of Alexander County lies within PSNC's certificated service territory and did not previously have natural gas service. The project was completed at a cost of approximately $4.8 million, and customers began receiving natural gas service in March 2000. SCANA Energy - Georgia See discussion at COMPETITION regarding the regulatory framework of the Company's business in the Georgia retail natural gas market. REGULATORY MATTERS - FEDERAL Effective with its acquisition of PSNC, SCANA became a registered public utility holding company under PUHCA. SCANA and its subsidiaries are subject to the jurisdiction of the SEC as to financings, acquisitions and diversifications, affiliate transactions and other matters. The Company's regulated business operations were impacted by FERC Orders No. 636, 888 and 2000. 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. 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. As already noted, Order No. 2000 required utilities which operate electric transmission systems to submit plans for the possible formation of RTOs. In March 2001 FERC gave provisional approval to SCE&G and two other southeastern electric utilities to establish GridSouth Transco, LLC (GridSouth) as an independent regional transmission company, responsible for operating and planning the utilities' combined transmission systems. In July 2001 FERC expressed its desire that utilities throughout the United States combine their transmission systems to create four large independent regional operators, one each in the Northeast, Southeast, Midwest and West. Accordingly FERC ordered mediation talks to take place between the utilities forming GridSouth and certain groups that had proposed other RTOs. These talks were mediated by an administrative law judge, who issued her nonbinding mediation report to FERC in September 2001. The report made recommendations related to the formation of a Southeast regional RTO. While FERC has not acted on the mediation report, and the timing or impact of future FERC orders related to RTOs cannot be predicted, SCE&G expects to be reimbursed or to otherwise recover costs it has incurred in connection with RTO formation. CRITICAL ACCOUNTING POLICIES AND NEW ACCOUNTING STANDARDS Following are descriptions of the Company's accounting policies which are new or most critical in terms of reporting results of operations. SFAS 71 - SCANA's regulated utilities are subject to the provisions of SFAS 71, which require them to record certain assets and liabilities that defer the recognition of expenses and revenues to future periods as a result of being rate-regulated. Aside from other impacts which might be experienced as a result of deregulation or other significant changes in the regulatory environments of the utilities, SFAS 71 could cease to be applicable and the Company could be required to write off such regulatory assets and liabilities (see also COMPETITION). Provisions for bad debts / Allowances for doubtful accounts - As of each balance sheet date, SCANA and its subsidiaries evaluate the collectibility of accounts receivable and record allowances for doubtful accounts based on estimates of the level of actual write-offs which might be experienced. These estimates are based on, among other things, comparisons of the relative age of accounts and consideration of actual write-off history. Investments in debt and equity securities - SCANA and certain of its subsidiaries hold investments in marketable securities, some of which are subject to SFAS 115 mark-to-market accounting and some of which are considered cost basis investments for which determination of fair value historically has been considered impracticable. Equity holdings subject to SFAS 115 are categorized as "available for sale" and are carried at quoted market, with any unrealized gains and losses credited or charged to other comprehensive income within common equity on the Company's balance sheet. Debt securities are categorized as "held to maturity" and are carried at amortized cost. When indicated, and in accordance with its stated accounting policy, SCANA performs periodic assessments of whether any decline in the value of these securities to amounts below SCANA's cost basis is other than temporary. When other than temporary declines occur, write-downs are recorded through operations, and new (lower) cost bases are established. During 2001, as a result of a determination that an other than temporary decline in value (an impairment) had occurred, SCANA wrote down its investments in ITC^DeltaCom in the amount of approximately $35 million (net of tax). Similarly, on March 1, 2002 the Company determined that the decline in value of its investment in DTAG to below its cost basis of $20.30 per share was other than temporary, and recorded an impairment loss of approximately $160 million (after tax). (See Note 16 to Notes to Consolidated Financial Statements.) SCANA also from time to time holds investments in joint ventures, partnerships or other equity method investees for which evaluation of the existence and quantification of "other than temporary" declines in value may be required. Whenever indicated these write-downs are also recorded through earnings. During 2001 SCANA wrote down two such investments in the aggregate amount of $9 million (net of tax). Although SCANA invests in securities and business ventures, it does not hold investments in unconsolidated special purpose entities such as those described in SFAS 140, and it does not engage in off-balance sheet financing or similar transactions other than incidental operating leases in the normal course of business, generally for office space, furniture and equipment. Goodwill amortization and impairment analysis - SFAS 141, "Business Combinations," and SFAS 142, "Goodwill and Other Intangible Assets," were issued during 2001. SFAS 141 will require all future acquisitions to be accounted for utilizing the purchase method. SCANA considers the amounts categorized by FERC as "acquisition adjustments" to be goodwill as defined in SFAS 142 and has ceased amortization of such amounts upon the adoption of SFAS 142 effective January 1, 2002. In 2001 the amount of such amortization expense recorded was $14 million. This amortization related to acquisition adjustments of approximately $466 million carried on the books of PSNC and approximately $40 million carried on the books of SCPC. As required by the provisions of SFAS 142, the Company is performing initial valuation analyses to determine whether these carrying amounts are impaired, and if so, the amount of any write-down which might be recorded as the cumulative effect of the change in accounting principle. As allowed by the Statement the Company will have completed the initial stage of those analyses by June 30, 2002. If any write-downs are indicated by those analyses, they will be quantified and recorded by the end of 2002. Because the Company is in the early stages of these analyses the effect, if any, of the adoption of the impairment provisions of the Statement is not known; however, if write-downs are considered necessary, they could be material to the Company's results of operations for 2002. Pension accounting - SCANA follows SFAS 87 in accounting for its defined benefit pension plan. SCANA's plan is fully funded and as such, significant net pension income is reflected in the financial statements (see Results of Operations). SFAS 87 requires the use of several assumptions, the selection of which may have a large impact on the resulting benefit recorded. Among the more sensitive assumptions are those surrounding discount rates and returns on assets. Net pension income of $43.3 million recorded in 2001 reflects the use of an 8 percent discount rate and an assumed 9.5 percent long-term return on plan assets. SCANA believes that these assumptions are, and that the resulting pension income amount is, reasonable. Were SCANA to have alternatively selected a discount rate of 7.5 percent and a rate of return on assets of 9 percent, the net pension income recorded in 2001 would have been reduced by approximately $6.2 million. Accounting for postretirement benefits other than pensions - Similar to its pension accounting, SCANA follows SFAS 106 in accounting for its postretirement medical and life insurance benefits. This plan is unfunded, so no return on assets impacts the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. SCANA used a discount rate of 8 percent and recorded a net SFAS 106 cost of $17.5 million for 2001. Were the selected discount rate to have been 7.5 percent, the expense would have been approximately $0.5 million higher. Derivatives - Effective January 1, 2001 SCANA follows the provisions of SFAS 133 in accounting for its derivatives and hedging activities. Substantially all of SCANA's use of derivatives occurs in the normal course of its risk management processes and is generally confined to contracts which qualify for hedge accounting treatment under the provisions of SFAS 133. The Company is party to interest rate swaps and to NYMEX traded natural gas contracts. The Company values its NYMEX gas derivatives at fair value based on quoted market prices, and values an insignificant number (and value) of non-exchange traded gas-related derivatives using information provided by counterparties to those transactions or by reference to quoted market prices of listed contracts. The estimated fair value of interest rate swaps is similarly based on settlement amounts obtained from the counterparties. 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 and losses related to qualifying cash flow hedges deferred in other comprehensive income will be reclassified to earnings at the time the hedged transactions affect earnings. SFAS 143, "Accounting for Asset Retirement Obligations," provides guidance for recording and disclosing a liability related to the future obligation to retire an asset (such as a nuclear plant). The Company will adopt SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on the Company's results of operations, cash flows or financial position has not been determined but could be material. The provisions of SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," are effective January 1, 2002. This Statement requires that one accounting model be used for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired, and broadens the presentation of discontinued operations to include more disposal transactions. There was no impact on the Company's financial statements from the initial adoption of SFAS 144. AFFILIATE TRANSACTIONS SCANA and its consolidated affiliates engage in certain intercompany transactions, subject to the restrictions imposed by PUHCA. Among these transactions are the sale of gas to SCE&G by SCPC and the provision of administrative services to all members of the consolidated group by SCANA Services. In addition to these transactions and investment transactions discussed at "Other Matters," the Company has engaged in the following transactions with other entities considered to be affiliates. SCE&G has two equity-method investments in partnerships involved in converting coal to alternate fuel, the use of which fuel qualifies for favorable Federal income tax treatment (tax credits). The aggregate investment in these partnerships as of December 31, 2001 is approximately $3 million, and through December 31, 2001, they had generated and passed through to SCE&G approximately $28 million in such tax credits. Under a plan approved by the SCPSC, any tax credits generated and ultimately passed through to SCE&G have been and will be deferred and used to offset defined capital expenditures such as those related to reduction of environmental emissions. OTHER MATTERS Radio Service Network SCI owns an 800 Mhz radio service network within South Carolina, and in June 2001, agreed to subcontract the operation and maintenance of its network to Motorola, Inc. (Motorola) for the period July 1, 2001 through March 31, 2002. SCI intends to sell the network to Motorola at a purchase price in excess of its carrying value. Claims and Litigation In 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. SCANA and Westvaco each own a 50 percent interest in Cogen South LLC (Cogen). Cogen built and operates a cogeneration facility in North Charleston, South Carolina. On September 10, 1998 the contractor in charge of construction filed suit in Circuit Court 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 named as defendants in the suit. Cogen filed a separate suit against the contractor for delay and performance issues. The suits were combined and the contractor brought the manufacturer of the generator into the performance suit. In November 2001 a settlement was reached between all parties. Terms of the settlement are confidential, but the settlement's impact on SCANA and SCE&G's results of operations, cash flow and financial position is not material. 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.

Telecommunications Investments At December 31, 2001 SCANA and SCH, a wholly owned, indirect subsidiary of SCANA, held investments in the marketable equity and debt securities of the following companies in the amounts noted in the table below. Unrealized Investee Held By Securities (a) Basis Market (b) Gain/(Loss) (c) ------------------------------ ------------------------------------------------------- ----------------- ----------- --------------- (Millions of dollars) DTAG SCH 39.3 million ordinary shares $798.0 $664.3 ($133.7) ITC SCH 3.1 million common stock 5.8 n/a (d) SCH 645,153 series A convertible preferred stock 7.2 n/a (d) SCH 133,664 series B convertible preferred stock 4.0 n/a (d) ITC^DeltaCom SCH 5.1 million common stock 4.4 - 4.4 (e) SCH 1.5 million series A convertible preferred stock, convertible March 2002 2.6 - 2.6 (e) SCANA 5,113 series B-1 preferred stock convertible into 877,193 shares of common stock 0.8 - 0.8 (e) SCANA 6,667 series B-2 preferred stock convertible into 2,604,297 shares of common stock 2.3 - 2.3 (e) SCANA Warrants to purchase approximately 1.0 million shares of common stock 0.8 - 0.8 (e) Knology SCH 7.2 million series A preferred stock, convertible 5.0 (d) n/a upon an initial public offering and warrants to purchase 159,000 shares of series A preferred stock, convertible upon an initial public offering SCH 8.3 million series C preferred stock, convertible 25.0 (d) n/a upon an initial public offering Knology Broadband SCH $71,050,000 face amount, 11.875% Senior Discount Notes due 2007 64.9 (d) n/a

(a) Convertible preferred stock is convertible into common stock at any time unless otherwise indicated. (b) As converted, based on market value of underlying common stock, where applicable. (c) Amounts are included in accumulated other comprehensive income (loss), net of taxes. (d) Market value not readily determinable. (e) Reflects write-down for "other than temporary" impairment as discussed below. DTAG is an international telecommunications carrier. The Company's investment in DTAG was received in exchange for approximately 14.9 million shares of Powertel, Inc. (Powertel) which SCH owned prior to DTAG's acquisition of Powertel in May 2001. SCH recorded a non-cash, after-tax gain of $354.4 million as a result of the exchange. On March 1, 2002 the Company determined that the decline in value of its investment in DTAG to below its cost basis of $20.30 per share was other than temporary, and recorded an impairment loss of approximately $160 million (after tax). (See Note 16 of Notes to Consolidated Financial Statements.) On March 21, 2002 the Company announced that SCH had sold 21 million ordinary shares of DTAG at a weighted average price of $14.82 per share through a series of market transactions between March 4, 2002 and March 21, 2002. The sales resulted in net after tax proceeds of approximately $250 million. ITC Holding Company (ITC) holds ownership interests in several Southeastern communications companies. ITC^DeltaCom is a fiber optic telecommunications provider and an affiliate of ITC. Knology, Inc. (Knology) is a broadband service provider of cable television, telephone and internet services. Knology is an affiliate of ITC. Knology Broadband, Inc. (Knology Broadband) is a wholly-owned subsidiary of Knology and an affiliate of ITC. In the fourth quarter of 2001 the Company determined that the decline in value of its investment in ITC^DeltaCom (to below cost) was other than temporary. Accordingly the Company recorded an impairment charge of approximately $35.0 million (after-tax). RESULTS OF OPERATIONS Earnings and Dividends Earnings per share of common stock and cash dividends declared for 2001, 2000 and 1999 were as follows: 2001 2000 1999 ------------------------------------------------------------------------------ ------------------------------------------------------------------------------ Earnings derived from: Continuing operations $2.15 $2.12 $1.39 Non-recurring gains 3.42 - .34 Investment impairment (.42) - - Cumulative effect of accounting change, net of taxes - .28 - ------------------------------------------------------------------------------ Earnings per weighted average share $5.15 $2.40 $1.73 ============================================================================== Cash dividends declared (per share) $1.20 $1.15 $1.32 ============================================================== =========== === o 2001 vs 2000 Earnings derived from continuing operations increased $.03, primarily as a result of improved results from retail gas marketing ($.03), improved results from energy marketing ($.09), completion of repairs at Summer Station in 2000 ($.04), a decrease in imputed interest expense related to the PSNC acquisition in 2000 ($.05) and other ($.02). These improvements were partially offset by a decrease in electric margin ($.11) and a decrease in regulated gas margin ($.09). 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 $.45 loss in 1999) and the acquisition of PSNC ($.20). 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 operation and maintenance ($.04). Pension income recorded by the Company reduced operations expense by $22.6 million, $22.6 million and $17.3 million for the years ended December 31, 2001, 2000 and 1999, respectively. In addition pension income increased other income by $12.7 million, $12.8 million and $10.5 million for the years ended December 31, 2001, 2000 and 1999, respectively. 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. In 2001 the Company recognized a non-recurring gain of $3.38 per share in connection with the sale of its investment in Powertel, which was acquired by DTAG in May 2001. The Company also recognized a gain of $.04 per share in connection with the sale of the assets of SCANA Security in March 2001. In 2001 the Company also recorded impairment charges related to investments in ITC^DeltaCom ($.34), a developer of micro-turbine technology ($.04) and a lime production plant ($.04). 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). Non-recurring gains resulted from the sale of retail propane assets ($.29) and telecommunications towers ($.05) in 1999. The Company's financial statements include the recording of an 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 3.0 percent of income before income taxes in 2001, 2.3 percent in 2000 and 2.4 percent in 1999. 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) for 2001, 2000 and 1999, excluding the cumulative effect of accounting change in 2000, were as follows: Millions of dollars 2001 2000 1999 --------------------------------------------- --------------- ---------------- Operating revenues $1,368.7 $1,343.8 $1,226.0 Less: Fuel used in generation (283.3) (294.9) (284.6) Purchased power (138.1) (82.5) (35.9) --------------------------------------------- ------------- -- ---------------- Margin $947.3 $966.4 $905.5 ============================================= =============== ================ o 2001 vs 2000 Sales margin decreased primarily due to milder weather and the impact of the slowing economy, which was partially offset by customer growth and lower fuel costs. o 2000 vs 1999 Sales margin increased primarily due to more favorable weather and 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 in 2000, were as follows:

Classification 2001 % Change 2000 % Change ------------------------------------------------- ------------------ ------------- ------------ Residential (170,509) (2.5%) 6.3% 396,179 Commercial (16,830) - 6.0% 354,350 Industrial (317,659) (4.8%) 8.5% 524,969 Sales for resale (excluding interchange) (108,236) (8.8%) 2.8% 33,505 Other (18,927) (3.4%) 6.7% 34,676 ------------------------------------------------- ------------- Total territorial (632,161) (3.0%) 1,343,679 6.7% Negotiated Market Sales Tariff 207,984 10.0% 15.7% 264,257 ------------------------------------------------- ------------- Total (424,177) (2.0%) 1,607,936 7.4% ================================================= ================== ============= ============

o 2001 vs 2000 Sales volume decreased primarily due to milder weather and the impact of the slowing economy. o 2000 vs 1999 Sales volume increased primarily due to more favorable weather and customer growth. In March 2001 Summer Station returned to service after having been taken out of service on October 7, 2000 for a planned maintenance and refueling outage. During initial inspection activities, plant personnel discovered a small leak in a weld in a primary coolant system pipe. Repairs were completed and the integrity of the new welds was verified through extensive testing. The NRC was closely involved throughout this process and approved SCE&G's actions, as well as the restart schedule. Also in April 2001 SCE&G's 385 megawatt coal-fired Cope Generating Station returned to service after having been taken out of service in January 2001 due to an electrical ground in the generator. The SCPSC has approved recovery of the cost of replacement power related to both of these outages through SCE&G's fuel adjustment clause. Gas Distribution Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC. Gas distribution sales margins (including transactions with affiliates) for 2001, 2000 and 1999, excluding the cumulative effect of accounting change in 2000, were as follows: Millions of dollars 2001 2000 1999 ---------------------------------------- ------------- ------------- Operating revenues 793.6 $745.9 $239.0 Less: Gas purchased for resale 537.8) (486.3) (152.6) ---------------------------------------- ------------- ------------- Margin 255.8 $259.6 $86.4 ======================================== ============= ============= SCANA acquired PSNC effective January 1, 2000. Therefore the Company's sales for 1999 do not include PSNC. o 2001 vs 2000 Sales margin decreased primarily as a result of the slowing economy and increased competition with alternate fuels. 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. 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 in 2000, were as follows: Classification 2001 % Change 2000 % Change ------------------------------- ------------- Residential (7,068,050) (18.1%) 27,211,306 230.2% Commercial (2,613,154) (10.0%) 14,493,448 123.9% Industrial (2,859,885) (12.7%) 4,484,199 25.0% Transportation gas (3,318,646) (10.5%) 29,523,281 * Sales for resale * * 882 407 ----------------------------------- ------------- Total (15,858,853) (13.3%) 75,712,641 174.2% =================================== =============== ============= ============= *Not meaningful o 2001 vs 2000 Sales volume decreased due to the slowing economy and use of alternate fuels by industrial customers. o 2000 vs 1999 Sales volume increased primarily as a result of the acquisition of PSNC, which accounted for 72.6 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. Gas Transmission Gas Transmission is comprised of SCPC. Gas transmission sales margins (including transactions with affiliates) for 2001, 2000 and 1999 were as follows: Millions of dollars 2001 2000 1999 ------------------------------------------ ------------- ------------- Operating revenues $478.0 $489.0 $342.4 Less: Gas purchased for resale (434.1) (434.7) (295.1) ------------------------------------------ ------------- ------------- Margin $43.9 $54.3 $47.3 ========================================== ============= ============= o 2001 vs 2000 Sales margin decreased primarily as a result of decreased volume of sales to industrial customers due to competitive pricing of alternate fuels and a slowing economy, decreased volume of sales to electric generation due to milder weather and reduced margins in sales for resale as a result of milder weather. o 2000 vs 1999 Sales margin increased primarily as a result of increased contract and sales volumes from sales for resale and margin earned from industrial customers. Increases (decreases) from the prior year in DT sales volume by classes including transportation were as follows: Classification 2001 % Change 2000 % Change ---------------------------------- ---------------------------------------- Commercial (422,070) (37.2%) 22,132 24.2% Industrial (101,275,260) (25.8%) (5,212,904) (11.7%) Transportation 7,250,560 32.1% 10,296 0.5% Sales for resale (95,295,980) (15.3%) 3,542,185 6.0% ---------------------------------- --------------- Total (189,742,750) (18.3%) (1,638,291) (1.6%) ================================== ======================================== o 2001 vs 2000 Commercial and industrial volumes decreased due to increased gas to gas competition and the slowing economy. Transportation volumes increased due to increased gas to gas competition. Sales for resale volumes decreased due to milder weather. 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. 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 (loss) for 2001, 2000 and 1999 were as follows: Millions of dollars 2001 2000 1999 ----------------------------------- --------------- ---------------- Operating revenues $628.1 $547.3 $206.6 Net income (loss) 7.6 4.4 (44.8) ----------------------------------- --------------- ---------------- o 2001 vs 2000 Operating revenues increased due to cold weather and record high gas costs early in the year. Net income increased primarily as a result of increases in gross margins on gas sales. o 2000 vs 1999 Operating 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. Delivered volumes for 2001, 2000 and 1999 totaled approximately 76.7 million, 73.8 million and 40.9 million DT, respectively, which include interruptible volumes of approximately 40.7 million, 30.6 million and 18.9 million DT for the same periods, respectively. Energy Marketing Energy Marketing is comprised of the Company's non-regulated marketing operations, excluding SCANA Energy. Energy marketing operating revenues and net income(loss) for 2001, 2000 and 1999 were as follows: Millions of dollars 2001 2000 1999 --------------------------------- --------------- ---------------- Operating revenues $438.9 $543.8 $223.3 Net income (loss) 2.6 (4.2) (3.9) --------------------------------- --------------- ---------------- o 2001 vs 2000 Operating revenues decreased primarily due to lower prices for natural gas in the latter part of the year and the closing of the Midwest and California offices. Net income increased primarily due to improved margins. o 2000 vs 1999 Operating revenues increased primarily due to increased prices for natural gas. Net loss increased primarily due to increased bad debts. Delivered volumes for 2001, 2000 and 1999 totaled approximately 75.3 million, 83.9 million and 103.7 million DT, respectively. The decrease in volumes for 2001 resulted from the closing of the Midwest and California offices and the decrease in volumes for 2000 resulted from the closing of the Houston office. Other Operating Expenses Increases in other operating expenses were as follows: Millions of dollars 2001 % Change 2000 % Change ------------------------------------------- ------------------------------------ Other operation and maintenance $3.5 0.7% $66.1 16.1% Depreciation and amortization 7.2 3.3% 47.4 28.1% Other taxes 1.5 21.3% 10.6 10.3% ------------------------------------------- ----------- Total $12.2 1.5% $124.1 18.2% =========================================== ==================================== o 2001 vs 2000 Other operation and maintenance expenses increased primarily as a result of increases in employee benefit costs. Depreciation and amortization increased primarily as a result of normal increases in utility plant. Other taxes increased primarily due to increased property taxes. o 2000 vs 1999 Other operating expenses 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. Other Income Increases (decreases) in other income, excluding the equity component of AFC, were as follows: Millions of dollars 2001 % Change 2000 % Change --------------------------------------- ------------ ------------ ------------ Gain on sale of investments $545.3 * - - Gain on sale of assets 10.1 * $(64.8) (95.3%) Impairment of investments (61.9) * - - Other income 0.8 2.1% 18.6 96.4% --------------------------------------- ------------ Total $494.3 * $(46.2) (52.9%) ======================================= ============ ============ ============ *Not meaningful o 2001 vs 2000 Other income increased primarily as a result of the non-recurring gain recognized in May 2001 in connection with the exchange of the Company's investment in Powertel for shares of DTAG, and the March 2001 gain on the sale of the assets of SCANA Security. These gains were partially offset by the impairments recorded related to investments in ITC^DeltaCom, a developer of micro-turbine technology and a lime production plant. o 2000 vs 1999 Other income decreased primarily as a result of the sale in 1999 of nonregulated propane assets and telecommunications towers. Interest Expense Increases (decreases) in interest expense, excluding the debt component of AFC, were as follows: Millions of dollars 2001 % Change 2000 % Change ---------------------------------------------------------------------------- Interest on long-term debt, net $17.8 8.6% $73.8 55.8% Other interest expense (14.4) (58.8%) 10.7 77.5% --------------------------------------------- ---------- Total $3.4 1.5% $84.5 57.9% ============================================================================ o 2001 vs 2000 Interest expense increased primarily as a result of increased borrowings which was partially offset by declining variable interest rates, the Company's use of interest rate swap contracts to convert higher fixed rate debt to lower variable rate debt and a decrease in the weighted average interest rate on other long-term and short-term debt. o 2000 vs 1999 Interest 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. Income Taxes Income taxes increased approximately $163.8 million for the year 2001 compared to 2000 and increased approximately $29.7 million for the year 2000 compared to 1999. Changes in 2001 income taxes are primarily due to the recording of deferred income taxes in connection with the non-recurring gain recorded in May 2001 arising from the exchange of the Company's investment in Powertel for shares of DTAG. Changes in 2000 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, 2001 Expected Maturity Date Millions of dollars Liabilities 2002 2003 2004 2005 2006 Thereafter Total Fair Value ---------------------------------- --------- --------- --------- ---------- ----------- ----------- ----------- -------------- Long-Term Debt: Fixed Rate ($) 38.3 298.5 187.0 182.0 162.8 1,728.0 2,596.6 2,602.8 Average Fixed Interest Rate 7.21 6.38 7.58 7.43 8.63 7.02 6.64 Variable Rate ($) 700.0 202.0 - - - - 902.0 898.2 Average Variable Interest Rate 2.82 3.45 - - - - 2.96 Interest Rate Swaps: Pay Variable/Receive Fixed ($) - - 12.9 - - 332.0 344.9 1.2 Average Pay Interest Rate - - 7.82 - - 2.96 3.15 Average Receive Interest Rate - 10.0 - - 6.21 6.35 - December 31, 2000 Expected Maturity Date Millions of dollars Liabilities 2001 2002 2003 2004 2005 Thereafter Total Fair Value ---------------------------------- --------- ---------- ---------- ---------- ---------- ----------- ---------- -------------- Long-Term Debt: Fixed Rate ($) 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 7.25 7.35 Variable Rate ($) 550.0 150.0 - - - 700.0 699.7 - Average Variable Interest Rate 7.26 7.48 - - - 7.31

- 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 an investment in the 11.875 percent senior discount notes (due 2007) of a telecommunications company, the cost basis of which is approximately $64.9 million. As these notes are not actively traded, determination of their fair value is not practicable. 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, 2001 Expected Maturity in 2002 Expected Maturity in 2003 ------------------ ---------------------------- -------------------------- Millions of dollars Weighted Weighted Avg Avg Settlement Contract Fair Settlement Contract Fair Natural Gas Derivatives: Price Amount Value Price Amount Value ----------------------------- ------------- --------------- ----------- -------------- ------------ ----------- Futures Contracts: Long ($) 2.63 119.3 76.0 3.26 3.0 2.6 Short ($) 2.64 1.6 1.1 - - - December 31, 2000 Expected Maturity in 2001 ------------------ ------------------------- Millions of dollars Weighted Avg Contract Fair Natural Gas Derivatives: Settlement Price Amount Value ------------------------------------- ------------------- ---------------- ------------ Futures Contracts: Long ($) 6.58 60.0 85.9 Short ($) 6.30 1.4 2.1

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options and over-the-counter instruments such as swaps, which are typically offered by energy and financial institutions. Risk limits are established to control the level of market, credit, liquidity and operational/administrative risks assumed by the Company. The Company's Board of Directors has delegated the authority for setting market risk limits to the Risk Management Committee, which is comprised of members of senior management, the Company's Controller, the Senior Vice President of SCPC and the President of Energy Marketing. The Risk Management Committee provides assurance to the Board of Directors with regard to compliance with risk management policies and brings to the Board's attention any areas of concern. Written policies define the physical and financial transactions that are approved as well as the authorization requirements for transactions that are allowed. The NYMEX futures information above includes those financial positions of both Energy Marketing and SCPC. The ultimate effects of the hedging activities of SCPC are passed through to its customers through SCPC's fuel adjustment clauses. Equity price risk - Investments in telecommunications companies' equity securities are carried at their market value or, if market value is not readily determinable, at their cost. The Company's investments in such securities totaled $722.3 million at December 31, 2001. A temporary decline in value of ten percent would result in a $72.2 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. An other than temporary decline in value of ten percent would result in a $72.2 million reduction in fair value and a corresponding adjustment to net income, net of tax effect. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL DATA Page Independent Auditors' Report............................................ 47 Consolidated Financial Statements: Consolidated Balance Sheets as of December 31, 2001 and 2000.......... 48 Consolidated Statements of Income for the Years Ended December 31, 2001, 2000 and 1999.................................. 50 Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999...................................................... 51 Consolidated Statements of Capitalization as of December 31, 2001 and 2000. 52 Consolidated Statements of Comprehensive Income and Changes in Common Equity for the Years Ended December 31, 2001, 2000 and 1999..........54 Notes to Consolidated Financial Statements...............................55 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, 2001 and 2000 and the related Consolidated Statements of Income, Comprehensive Income and Changes in Common Equity and of Cash Flows for each of the three years in the period ended December 31, 2001. 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, 2001 and 2000 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 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 as 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 8, 2002 (March 1, 2002 as to Note 16)

SCANA Corporation CONSOLIDATED BALANCE SHEETS -------------------------------------------------------------------------------------------- --------------------- December 31, (Millions of dollars) 2001 2000 -------------------------------------------------------------------------------------------- --------------------- Assets Utility Plant (Notes 1 & 6): Electric $4,855 $4,747 Gas 1,536 1,435 Other 187 187 -------------------------------------------------------------------------------------------- --------------------- Total 6,578 6,369 Less accumulated depreciation and amortization 2,364 2,212 -------------------------------------------------------------------------------------------- --------------------- Total 4,214 4,157 Construction work in progress 544 261 Nuclear fuel, net of accumulated amortization 45 57 Acquisition adjustments-gas, net of accumulated amortization (Note 3) 460 474 -------------------------------------------------------------------------------------------- --------------------- Utility Plant, Net 5,263 4,949 -------------------------------------------------------------------------------------------- --------------------- Nonutility Property, net of accumulated depreciation 93 79 Investments (Note 12) 191 203 -------------------------------------------------------------------------------------------- --------------------- Nonutility Property and Investments, Net 284 282 -------------------------------------------------------------------------------------------- --------------------- Current Assets: Cash and temporary investments (Notes 1 & 12) 212 159 Receivables (Net of allowance for uncollectible accounts of $37 and $31) 424 694 Inventories (At average cost) (Note 7): Fuel 164 107 Materials and supplies 59 56 Emission allowances 13 20 Prepayments and other 21 16 Investments (Note 12) 664 479 -------------------------------------------------------------------------------------------- --------------------- Total Current Assets 1,557 1,531 -------------------------------------------------------------------------------------------- --------------------- Deferred Debits: Environmental 34 31 Nuclear plant decommissioning fund (Note 1) 79 72 Pension asset, net (Note 5) 239 196 Other regulatory assets (Note 1) 210 213 Other (Note 1) 156 153 -------------------------------------------------------------------------------------------- --------------------- Total Deferred Debits 718 665 -------------------------------------------------------------------------------------------- --------------------- Total $7,822 $7,427 ============================================================================================ =====================

182

------------------------------------------------------------------------- --------------------- --------------------- December 31, (Millions of dollars) 2001 2000 ------------------------------------------------------------------------- --------------------- --------------------- Capitalization and Liabilities Shareholders' Investment: Common equity (Note 9) $2,194 $2,032 Preferred stock (Not subject to purchase or sinking funds) (Note 10) 106 106 ------------------------------------------------------------------------- --------------------- --------------------- Total Shareholders' Investment 2,300 2,138 Preferred Stock, net (Subject to purchase or sinking funds) (Note 10) 10 10 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) 2,646 2,850 ------------------------------------------------------------------------- --------------------- --------------------- Total Capitalization 5,006 5,048 ------------------------------------------------------------------------- --------------------- --------------------- Current Liabilities: Short-term borrowings (Notes 7, 8 & 12) 165 398 Current portion of long-term debt (Note 6) 739 41 Accounts payable 275 394 Customer prepayments and deposits 41 27 Taxes accrued 82 54 Interest accrued 45 42 Dividends declared 34 32 Deferred income taxes, net (Notes 1 & 11) 154 98 Other 26 30 ------------------------------------------------------------------------- --------------------- --------------------- Total Current Liabilities 1,561 1,116 ------------------------------------------------------------------------- --------------------- --------------------- Deferred Credits: Deferred income taxes, net (Notes 1 & 11) 720 721 Deferred investment tax credits (Notes 1 & 11) 118 119 Reserve for nuclear plant decommissioning (Note 1) 79 72 Postretirement benefits (Note 5) 122 113 Other regulatory liabilities 100 70 Other 116 168 ------------------------------------------------------------------------- --------------------- --------------------- Total Deferred Credits 1,255 1,263 ------------------------------------------------------------------------- --------------------- --------------------- Commitments and Contingencies (Note 13) - - ------------------------------------------------------------------------- --------------------- --------------------- Total $7,822 $7,427 ========================================================================= ===================== =====================

See Notes to Consolidated Financial Statements.

SCANA Corporation CONSOLIDATED STATEMENTS OF INCOME ------------------------------------------------------------------------ ---------------- --------------- -------------- -- For the Years Ended December 31, 2001 2000 1999 ------------------------------------------------------------------------ ---------------- --------------- -------------- -- (Millions of Dollars, except per share amounts) Operating Revenues (Notes 1, 2 & 4): Electric $1,369 $1,344 $1,226 Gas - Regulated 1,015 998 422 Gas - Nonregulated 1,067 1,091 430 ------------------------------------------------------------------------ ---------------- --------------- ---------------- Total Operating Revenues 3,451 3,433 2,078 ------------------------------------------------------------------------ ---------------- --------------- ---------------- Operating Expenses: Fuel used in electric generation 283 295 285 Purchased power 138 82 36 Gas purchased for resale 1,681 1,694 721 Other operation and maintenance 482 477 411 Depreciation and amortization (Note 1) 224 217 169 Other taxes 115 114 103 ------------------------------------------------------------------------ ---------------- --------------- ---------------- Total Operating Expenses 2,923 2,879 1,725 ------------------------------------------------------------------------ ---------------- --------------- ---------------- Operating Income 528 554 353 ------------------------------------------------------------------------ ---------------- --------------- ---------------- Other Income (Expense): Other income, including allowance for equity funds used during construction (Note 1) 54 41 22 Gain on sale of assets 13 3 68 Gain on sale of investments (Note 12) 545 - - Impairment of investments (Note 12) (62) - - ------------------------------------------------------------------------ ---------------- --------------- ---------------- Total Other Income 550 44 90 ------------------------------------------------------------------------ ---------------- --------------- ---------------- Income Before Interest Charges, Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change 1,078 598 443 Interest Charges, Net of Allowance for Borrowed Funds 223 225 142 ------------------------------------------------------------------------ ---------------- --------------- ---------------- Income Before Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change 855 373 301 Income Taxes (Note 11) 305 141 111 ------------------------------------------------------------------------ ---------------- --------------- ---------------- Income Before Preferred Stock Dividends and Cumulative Effect of Accounting Change 550 232 190 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 546 228 186 Cash Dividends on Preferred Stock of Subsidiary (At stated rates) 7 7 7 ------------------------------------------------------------------------ ---------------- --------------- ---------------- Income Before Cumulative Effect of Accounting Change 539 221 179 Cumulative Effect of Accounting Change, net of taxes (Note 2) - 29 - ------------------------------------------------------------------------ ---------------- --------------- ---------------- Net Income $539 $250 $179 ======================================================================== ================ =============== ================ Basic and Diluted Earnings Per Share of Common Stock: Before Cumulative Effect of Accounting Change $5.15 $2.12 $1.73 Cumulative Effect of Accounting Change, net of taxes (Note 2) - .28 - ------------------------------------------------------------------------ ---------------- --------------- ---------------- Basic and Diluted Earnings Per Share $5.15 $2.40 $1.73 ======================================================================== ================ =============== ================ Weighted Average Shares Outstanding (millions) 104.7 104.5 103.6 See Notes to Consolidated Financial Statements.

SCANA Corporation CONSOLIDATED STATEMENTS OF CASH FLOWS --------------------------------------------------------------------------------------- ---------------- -------------- ------------ For the Years Ended December 31, (Millions of dollars) 2001 2000 1999 --------------------------------------------------------------------------------------- ---------------- -------------- ------------ Cash Flows From Operating Activities: Net income $539 $250 $179 Adjustments to reconcile net income to net cash provided from operating activities: Cumulative effect of accounting change, net of taxes - (29) - Depreciation and amortization 236 227 177 Amortization of nuclear fuel 16 16 18 Gain on sale of assets and investments (558) (3) (68) Impairment of investments 62 - - Hedging activities (65) - - Allowance for funds used during construction (26) (9) (7) Over (under) collection, fuel adjustment clauses 20 (25) (6) Changes in certain assets and liabilities: (Increase) decrease in receivables 262 (258) (36) (Increase) decrease in inventories (53) 3 (14) (Increase) decrease in pension asset (43) (43) (29) (Increase) decrease in other regulatory assets (3) 4 19 Increase (decrease) in deferred income taxes, net 189 61 19 Increase (decrease) in other regulatory liabilities 22 6 (7) Increase (decrease) in postretirement benefits 9 15 11 Increase (decrease) in accounts payable (119) 155 (30) Increase (decrease) in taxes accrued 28 (55) 14 Other, net (20) 76 (15) --------------------------------------------------------------------------------------- ---------------- -------------- ------------ Net Cash Provided From Operating Activities 496 391 225 --------------------------------------------------------------------------------------- ---------------- -------------- ------------ Cash Flows From Investing Activities: Utility property additions and construction expenditures, net of AFC (523) (334) (238) Purchase of subsidiary, net of cash acquired - (212) - Proceeds on sale of assets 28 8 112 Increase in nonutility property (25) (27) (23) Increase in investments (46) (20) (74) --------------------------------------------------------------------------------------- ---------------- -------------- ------------ Net Cash Used For Investing Activities (566) (585) (223) --------------------------------------------------------------------------------------- ---------------- -------------- ------------ Cash Flows From Financing Activities: Proceeds from issuance of First Mortgage Bonds 149 148 99 Proceeds from issuance of notes and loans 648 998 200 Proceeds from swap settlement 6 - - Repayment of mortgage bonds - (100) (10) Repayment of notes and loans (317) (175) (77) Repayment of other long-term debt - (8) (10) Repurchase of preferred stock - (1) - Repurchase of common stock - (488) - Dividend payments on common stock (123) (124) (148) Dividend payments on preferred stock of subsidiary (7) (7) (7) Short-term borrowings, net (233) (6) 5 ------------------------------------------------------------------------------------------------------------------------------------ Net Cash Provided From Financing Activities 123 237 52 --------------------------------------------------------------------------------------- ---------------- -------------- ------------ Net Increase in Cash and Temporary Investments 53 43 54 Cash and Temporary Investments, January 1 159 116 62 --------------------------------------------------------------------------------------- ---------------- -------------- ------------ Cash and Temporary Investments, December 31 $212 $159 $116 ======================================================================================= ================ ============== ============ Supplemental Cash Flow Information: Cash paid for - Interest (net of capitalized interest of $11, $6 and $4) $219 $207 $138 - Income taxes 71 120 70 Noncash Investing and Financing Activities: Unrealized gain (loss) on securities available for sale, net of tax (226) (197) 311 In connection with the purchase of Public Service Company of North Carolina, Incorporated in 2000, assets with a fair value of $1,177 million were acquired, cash of $212 million was paid, SCANA stock valued at $488 million was issued, and liabilities of $477 million were assumed. See Notes to Consolidated Financial Statements.

SCANA Corporation CONSOLIDATED STATEMENTS OF CAPITALIZATION

---------------------------------------------------------------------------------------- ------------- ------- ------------ ------- December 31, (Millions of dollars) 2001 2000 ---------------------------------------------------------------------------------------- ------------- ------- ------------ ------- Common Equity (Note 9): Common stock, without par value, authorized 150,000,000 shares; issued and outstanding, 104,728,268 shares in 2001 and 2000 $1,043 $1,043 Accumulated other comprehensive income (loss) (113) 139 Retained earnings 1,264 850 ---------------------------------------------------------------------------------------- ------------- ------- ------------ ------- Total Common Equity 2,194 44% 2,032 40% ---------------------------------------------------------------------------------------- ------------- ------- ------------ ------- 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 Redemption Price Outstanding Series 2001 2000 ------ ---- ---- $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 2% ---------------------------------------------------------------------------------------- ------------- ------- ------------ ------- 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 2001 and 2000 $50 Par Value - Authorized 1,560,287 shares Shares Outstanding Redemption Price Series 2001 2000 ------ ---- ---- 4.50% 8,397 9,600 51.00 1 1 4.60% (A) 14,052 16,052 51.00 1 1 4.60% (B) 54,400 57,800 50.50 3 3 5.125% 66,000 67,000 51.00 3 3 6.00% 66,635 69,835 50.50 3 3 --------- ------------ Total 209,484 220,287 ========= ============ $25 Par Value - Authorized 2,000,000 shares; None outstanding in 2001 and 2000 ----------------------------------------------------------------------------------------- ------------ -------- ------------ ------- Total Preferred Stock (Subject to purchase or sinking funds) 11 11 Less: Current portion, including sinking fund requirements (1) (1) ----------------------------------------------------------------------------------------- ------------ -------- ------------ ------- Total Preferred Stock, Net (Subject to purchase or sinking funds) (Notes 10 & 12) 10 - % -% 10 ----------------------------------------------------------------------------------------- ------------ -------- ------------ ------- 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% 1% 50 ----------------------------------------------------------------------------------------- ------------ -------- ------------ -------

---------------------------------------------------------------------- -- -------------- -------- -------------- ----------- December 31, (Millions of dollars) 2001 2000 ---------------------------------------------------------------------- -- -------------- -------- -------------- ----------- Long-Term Debt (Notes 6 & 12) SCANA Corporation: Medium-Term Notes: Series Year of Maturity 3.08%(1) 2002 $300 $300 2.63%(2) 2002 400 400 6.51% 2003 20 20 6.05% 2003 60 60 6.25% 2003 75 75 3.45%(3) 2003 202 - 7.44% 2004 50 50 6.90% 2007 25 25 5.81% 2008 115 115 6.875% 2011 300 - (1) Current rate, based on three-month LIBOR + 65 basis points, reset quarterly (2) Current rate, based on three-month LIBOR + 50 basis points reset quarterly (3) Current rate, based on three-month LIBOR + 110 basis points, reset quarterly Bank note, due 2002-2003, LIBOR rate, reset 1, 2, 3 or 6 months - 300 South Carolina Electric & Gas Company: First Mortgage Bonds: Series Year of Maturity 6 1/4% 2003 100 100 7.70% 2004 100 100 7 1/2% 2005 150 150 6 1/8% 2009 100 100 6.70% 2011 150 - 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 16 17 Charleston Franchise Agreement, due 1997-2002 4 7 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 41 49 Public Service Company of North Carolina, Incorporated: Senior Debentures: Series Year of Maturity 10% 2004 13 17 8.75% 2012 32 32 6.99% 2026 50 50 7.45% 2026 50 50 Medium-Term Notes 6.625% 2011 150 - South Carolina SCPC Notes, 6.72%, due 2013 15 16 Other 7 4 ---------------------------------------------------------------------- -- -------------- -------- -------------- ----------- Total Long-Term Debt 3,382 2,894 Less - Current maturities, including sinking fund requirements (739) (41) - Unamortized premium (discount) 3 (3) ---------------------------------------------------------------------- -- -------------- -------- -------------- ----------- Total Long-Term Debt, Net 2,646 53% 2,850 57% ---------------------------------------------------------------------- -- -------------- -------- -------------- ----------- Total Capitalization $5,006 100% $5,048 100% ====================================================================== == ============== ======== ============== =========== See Notes to Consolidated Financial Statements.

SCANA Corporation CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND CHANGES IN COMMON EQUITY ------------------------------------------------ ------------------------- ------------------------- --------------------------- For the years Ended December 31, 2001 2000 1999 ------------------------------------------------ ------------------------- ------------------------- --------------------------- (Millions of Dollars) Common Comprehensive Common Comprehensive Common Comprehensive Equity Income Equity Income Equity Income Retained Earnings: Balance at January 1 $850 $720 $678 Net Income 539 $539 250 $250 179 $179 Dividends declared on common stock (125) (120) (137) --------- --------- ----- Balance at December 31 1,264 850 720 -- ----- ---- --- - --- Accumulated other comprehensive income: Balance at January 1 139 336 25 Unrealized gains (losses) on securities, net of taxes ($(121), $(106) and $165 in 2001, 2000, and 1999, respectively) (226) (226) (197) (197) 311 311 Cumulative effect of change in accounting For hedging activities, net of taxes 23 23 ($12 in 2001) Unrealized losses on hedging activities, net of taxes ($(26) in 2001) (49) - - - ---- --- ---- --------- ----- - ------ - (49) - ---- - Comprehensive income $287 $53 $490 ==== = === ==== Balance at December 31 (113) 139 336 ------- ---- --- - --- Common Stock: Balance at January 1 1,043 1,043 1,043 Shares issued 488 - - Shares repurchased - --------- ---- ------- - - (488) - ----- Balance at December 31 1,043 1,043 1,043 -- ----- -- ----- - ----- Total Common Equity $2,194 $2,032 $2,099 ====== ====== ======

During 2001, $354 million was reclassified from unrealized gains (losses) on securities into net income as a result of the exchange of (available for sale) shares of Powertel, Inc., for shares for Deutsche Telekom AG. Also in 2001, $(36) million was reclassified from unrealized gains (losses) on securities into net income as a result of the recording of an impairment of the ITC^DeltaCom, Inc. investment. 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 (the Company), a South Carolina corporation, is a registered public utility holding company within the meaning of the Public Utility Holding Company Act of 1935, as amended (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, 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 (SCPC) Primesouth, Inc. Public Service Company of North Carolina, SCANA Resources, Inc. Incorporated (PSNC) SCG Pipeline, Inc. SCANA Services, Inc. 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, 2001, approximately $244 million and $100 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities of approximately $142 million and $76 million, respectively. The electric and gas regulatory assets of approximately $52 million and $50 million, respectively (excluding deferred income tax assets), are recoverable through rates. The Public Service Commission of South Carolina (SCPSC) and the North Carolina Utilities Commission (NCUC) have reviewed and approved most of the items shown as regulatory assets through specific orders. Other items represent costs which were not yet approved for recovery by the SCPSC or the NCUC, but are the subject of current or future filings. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in current rate orders received by the Company. However, ultimate recovery is subject to SCPSC or NCUC approval. 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 SCPSC or, in the case of PSNC, the 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 $963.0 million and $965.0 million as of December 31, 2001 and 2000, respectively. Accumulated depreciation associated with SCE&G's share of Summer Station was approximately $407.4 million and $387.7 million as of December 31, 2001 and 2000, respectively. SCE&G's share of the direct expenses associated with operating Summer Station is included in "Other operation and maintenance" expenses. As allowed by the SCPSC, SCE&G accrues in advance its portion of estimated scheduled outage costs for Summer Station. Total outage costs for the planned outage in April 2002 are estimated to be approximately $13 million, of which SCE&G will be responsible for approximately $8.9 million. As of December 31, 2001, SCE&G had accrued $5.9 million. 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 8.8%, 8.3% and 8.1% for 2001, 2000 and 1999, 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). Unbilled revenues totaled approximately $81.5 million and $159.3 million as of December 31, 2001 and 2000, respectively. 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 SCPSC 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 $47.4 million and $35.5 million at December 31, 2001 and 2000, 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 SCPSC 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, 2001 and 2000 SCE&G had undercollected through the gas cost recovery procedure approximately $12.2 million and $12.7 million, respectively, which are included in "Deferred Debits - Other regulatory assets." At December 31, 2001 PSNC had overcollected through the gas cost recovery procedure approximately $13.8 million which amount is included in "Deferred Credits - Other regulatory liabilities." At December 31, 2000 PSNC had undercollected through the gas cost recovery procedure approximately $9.3 million which amount is 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: 2001 2000 1999 ------------------------------------- -------------- --------------- SCE&G 2.98% 2.98% 2.99% GENCO 2.71% 2.67% 2.56% SCPC 2.60% 2.58% 2.62% PSNC 4.06% 4.15% n/a Aggregate of Above 3.09% 3.09% 2.95% 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. The Company adopted SFAS 142, "Goodwill and Other Intangible Assets," on January 1, 2002. See Note 1N for further discussion. 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 one-third 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 2001, 2000 and 1999) 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 $2.4 million at December 31, 2001, 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 evaluate 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. Deferred amounts for SCE&G, net of amounts previously recovered through rates and insurance settlements, totaled $24.4 million and $20.2 million at December 31, 2001 and 2000, respectively. Deferred amounts for PSNC totaled $9.1 million and $10.2 million at December 31, 2001 and 2000, respectively. 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 Beginning January 1, 2001 the Company recognizes assets or liabilities for the energy-related contracts entered into by its subsidiaries when the contracts are executed. The Company records contracts at their fair value in accordance with SFAS 133 and adjusts fair value each reporting period. The Company derives fair value of most of the energy-related contracts from markets where they are actively traded and quoted. For other contracts the Company uses published market surveys and in certain cases, independent parties to obtain quotes concerning fair value. Market quotes tend to be more plentiful for those contracts maturing in two years or less. The vast majority of the Company's contracts do not extend beyond two years. (See Note 12). 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. New Accounting Standards In 2001 the Financial Accounting Standards Board issued the following new accounting standards that will be adopted by the Company. SFAS 141, "Business Combinations," and SFAS 142, "Goodwill and Other Intangible Assets," were issued during 2001. SFAS 141 will require all future acquisitions to be accounted for utilizing the purchase method. SCANA considers the amounts categorized by FERC as "acquisition adjustments" to be goodwill as defined in SFAS 142 and has ceased amortization of such amounts upon the adoption of SFAS 142 effective January 1, 2002. In 2001, the amount of such amortization expense recorded was $14 million. This amortization related to acquisition adjustments of approximately $466 million carried on the books of PSNC and approximately $40 million carried on the books of SCPC. As required by the provisions of SFAS 142, the Company is performing initial valuation analyses to determine whether these carrying amounts are impaired, and if so, the amount of any write-down which might be recorded as the cumulative effect of the change in accounting principle. As allowed by the Statement, the Company will have completed the initial stage of those analyses by June 30, 2002. If any write-downs are indicated by those analyses, they will be quantified and recorded by the end of 2002. Because the Company is in the early stages of these analyses, the effect, if any, of the adoption of the impairment provisions of the Statement is not known; however, if write-downs are considered necessary, they could be material to the Company's results of operations for 2002. SFAS 143, "Accounting for Asset Retirement Obligations," provides guidance for recording and disclosing a liability related to the future obligation to retire an asset (such as a nuclear plant). The Company will adopt SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on the Company's results of operations, cash flows or financial position has not been determined but could be material. The provisions of SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," are effective January 1, 2002. This Statement requires that one accounting model be used for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired, and broadens the presentation of discontinued operations to include more disposal transactions. There was no impact on the Company's financial statements from the initial adoption of SFAS 144. 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), and related interpretations. 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 2001. 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) for the year ended December 31, 1999 compared to $179 million ($1.73 per share) as reported. 3. ACQUISITION Effective January 1, 2000 the Company acquired PSNC in a business combination accounted for as a purchase. PSNC is a public utility engaged primarily in purchasing, transporting, distributing and selling natural gas to approximately 379,000 residential, commercial and industrial customers in 26 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 Electric On April 24, 2001 the SCPSC approved SCE&G's request to increase the fuel component of rates charged to electric customers from 1.330 cents per kilowatt-hour to 1.579 cents per kilowatt-hour. The increase reflects higher fuel costs projected for the period May 2001 through April 2002. The increase also provides recovery over a two-year period of under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of SCE&G's base load generating plants in winter 2000-2001. The new rates were effective as of the first billing cycle in May 2001. On September 14, 1999 the SCPSC 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 SCPSC 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 SCPSC. 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, 2001 no accelerated depreciation has been recorded. The accelerated capital recovery plan will be accomplished through existing customer rates. On January 9, 1996 the SCPSC authorized a return on common equity of 12.0 percent. The SCPSC 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 SCPSC approved accelerated amortization 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, which enabled SCE&G to recover the balances as of the end of the year 2000. Gas SCE&G's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by SCE&G. SCE&G's cost of gas component in effect during the years ended December 31, 2001and 2000 was as follows: Rate Per Therm Effective Date Rate Per Therm Effective Date $.993 January-February 2001 $.543 January-July 2000 $.793 March-October 2001 $.688 August-October 2000 $.596 November-December 2001 $.782 November-December 2000 On July 5, 2000 the SCPSC 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. The retroactive effect was recorded in the second quarter of 2000. In 1994 the SCPSC 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 October 2001, as a result of the annual review, the SCPSC approved SCE&G's request to increase the billing surcharge from 1.1 cents per therm to 3.0 cents per therm, which is intended to provide for the recovery of the balance remaining at December 31, 2001 of $24.4 million prior to the end of the year 2005. Transit In September 1992 the SCPSC 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 SCPSC also required $.40 fares for low income customers and denied SCE&G's request for certain bus route and schedule changes. The new rates were placed into effect in October 1992. After several appeals and petitions for reconsideration to the South Carolina Circuit Court (Circuit Court) and the South Carolina Supreme Court (Supreme Court) by the various parties, on September 27, 2000 the SCPSC issued an order granting certain relief requested by SCE&G. On September 29, 2000 the Consumer Advocate of South Carolina (Consumer Advocate) filed a motion with the SCPSC for a stay of this order. On October 3, 2000 the SCPSC 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 SCPSC's order granting relief. The Circuit Court has held in abeyance any appellate review pending the outcome of current negotiations on the transfer of the transit system from SCE&G to an unaffiliated regional transit authority. Public Service Company of North Carolina, Incorporated PSNC's rates are established using a benchmark 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. PSNC's benchmark cost of gas in effect during the years ended December 2001 and 2000 was as follows: Rate Per Therm Effective Date Rate Per Therm Effective Date $.690 January 2001 $.300 January 2000 $.750 February-March 2001 $.265 February-May 2000 $.650 April-August 2001 $.350 June 2000 $.500 September-October 2001 $.450 July-September 2000 $.350 November-December 2001 $.490 October-December 2000 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. This mechanism allows PSNC to collect from its customers amounts approximating the amounts paid for natural gas. 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. On June 29, 2000 the NCUC approved PSNC's requests for 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. The Madison County portion of the project was completed at a cost of approximately $5.8 million, and customers began receiving service in July 2001. On December 7, 1999 the NCUC issued an order approving SCANA's acquisition of PSNC. As specified in the NCUC order, PSNC reduced its rates by approximately $1 million in each of August 2000 and August 2001, and agreed to a moratorium on general rate cases until August 2005. 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 . Most of Alexander County lies within PSNC's certificated service territory and did not previously have natural gas service. The project was completed at a cost of approximately $4.8 million, and customers began receiving natural gas service in March 2000. 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. 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. In connection with the joint ownership arrangements surrounding Summer Station, as of December 31, 2001 the Company has recorded within deferred credits an $8.4 million obligation to Santee Cooper, representing an estimate of the net pension asset attributable to the Company's contributions to the plan that were recovered through billings to Santee Cooper for its one-third portion of shared costs. The Company has also recorded a $6.0 million receivable from Santee Cooper, representing an estimate of its portion of the unfunded net postretirement benefit obligation. As allowed by SFAS 87, the Company records net periodic benefit cost (income) utilizing beginning of the year assumptions. 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 2001 2000 1999 2001 2000 1999 ---- ---- ---- ---- ---- ---- Service cost $7.9 $ 8.3 $10.0 $3.0 $ 2.7 $ 3.0 Interest cost 38.5 33.5 27.9 12.1 10.2 9.5 Expected return on assets (83.5) (76.6) (65.5) n/a n/a n/a Prior service cost amortization 5.8 3.0 1.1 0.9 0.8 0.7 Actuarial (gain) loss (12.8) (12.2) (8.6) 0.7 - 1.2 Transition amount amortization 0.8 0.8 0.8 0.8 0.8 1.7 Special termination benefit cost - 5.5 - - 1.0 ------- -- ----- --- -------- - -------- ---- --- - Net periodic benefit (income) $(43.3) $(43.2) $(28.8) $17.5 $14.5 $17.1 ====== ====== ====== ===== ===== ===== cost Assumptions Retirement Benefits Other Postretirement Benefits -------------------------------------- -------------------------------------- As of December 31, 2001 2000 1999 2001 2000 1999 ---- ---- ---- ---- ---- ---- Discount rate 7.5% 8.0% 8.0% 7.5% 8.0% 8.0% 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 2001 2000 2001 2000 ---- ---- ---- ---- Benefit obligation, January 1 $479.3 $362.3 $139.0 $129.8 Service cost 7.9 8.3 3.0 2.7 Interest cost 38.5 33.5 12.1 10.2 Plan participants' contributions - 0.1 0.5 0.5 Plan amendment 21.5 65.4 1.2 0.9 Actuarial (gain) loss 19.6 1.6 20.1 (7.8) Acquisition/merger of plans - 39.8 - 11.2 Benefits paid (36.0) (31.7) (9.2) (8.5) -- ----- --- ----- ---- ---- ---- ---- Benefit obligation, December 31 $530.8 $479.3 $166.7 $139.0 ====== ====== ====== ====== Change in Plan Assets Retirement Benefits ---------------------------------------------------- Millions of dollars 2001 2000 ---- ---- Fair value of plan assets, January 1 $894.3 $783.0 Actual return on plan assets (26.7) 96.7 Company contribution - - Plan participants' contributions - 0.1 Acquisition/merger of plans - 46.2 Benefits paid (36.0) (31.7) -- ----- --- ----- Fair value of plan assets, December 31 $831.6 $894.3 ====== = ====== Funded Status of Plans Retirement Benefits Other Postretirement Benefits ------------------------ ------------------------------- Millions of dollars 2001 2000 2001 2000 ---- ---- ---- ---- Funded status, December 31 $300.8 $415.0 $(166.7) $(139.0) Unrecognized actuarial (gain) loss (155.0) (297.6) 32.5 13.0 Unrecognized prior service cost 89.4 73.7 4.8 4.5 Unrecognized net transition obligation 4.0 4.8 7.4 8.3 --------- ---------- -------- --- ----- --- Net amount recognized in Consolidated Balance Sheet $239.2 $195.9 $(122.0) $(113.2) ====== = ====== ======= =======

Health Care Trends The determination of net periodic other postretirement benefit cost is based on the following assumptions: 2001 2000 1999 --------------------------------------------------- ---------- ---------- Health care cost trend rate 8.5% 7.5% 8.0% Ultimate health care cost trend rate 5.0% 5.5% 5.5% Year achieved 2009 2005 2005 The effects 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 benefit cost $0.1 $(0.1) Effect on postretirement benefit obligation 1.6 (1.8) 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 and non-employee directors. 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. 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 Granted 716,368 $27.43 Exercised - n/a Forfeited (74,595) $26.93 ------------------------------------------------------- Outstanding - December 31, 2001 802,281 $26.64 ======================================================= 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. Information about outstanding and exercisable options as of December 31, 2001 follows: Options Outstanding Options Exercisable Weighted Range Average Weighted Weighted of Number Remaining Average Number Average Exercise of Contractual Exercise of Exercise Prices Options Life (in years) Price Options Price ------------------ ------------------------------------------------------------- $25.50 to $27.80 802,281 9.2 $26.64 47,275 $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," pro forma net income and earnings per share would have been as presented below: 2001 2000 ---- ---- Net income - as reported (millions) $539.3 $250.4 Net income - pro forma (millions) 538.5 250.3 Basic and diluted earnings per share - as reported 5.15 2.40 Basic and diluted earnings per share - pro forma 5.14 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 2001 and 2000 was $5.13 and $4.43, respectively, and was estimated using the Black-Scholes Option pricing model with the following weighted average assumptions. 2001 2000 ---- ---- Expected life of options (years) 7 10 Risk free interest rate 5.08% 5.99% Volatility of underlying stock 22% 21% Dividend yield of underlying stock 4.2% 4.4% 6. LONG-TERM DEBT The annual amounts of long-term debt maturities and sinking fund requirements for the years 2002 through 2006 are summarized as follows: Year Amount Year Amount --------------- ----------------- ------------------ ----------------- (Millions of dollars) 2002 $738.3 2005 $182.0 2003 500.3 2006 162.8 2004 187.0 --------------- ----------------- ------------------ ----------------- Approximately $23.5 million of the portion of long-term debt payable in 2002 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. 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. SCE&G's commercial paper outstanding totaled $114.7 million and $117.5 million at December 31, 2001 and 2000, at weighted average interest rates of 1.95 percent and 6.59 percent, respectively. Substantially all utility plant is pledged as collateral in connection with long-term debt. On January 31, 2002 SCANA issued $250 million medium-term notes maturing February 1, 2012 and bearing a fixed interest rate of 6.25 percent. Also on January 31, 2002 SCANA issued $150 million two-year floating rate notes maturing on February 1, 2004. The interest rate on the floating rate notes is reset quarterly based on three-month LIBOR plus 62.5 basis points. Proceeds from these issuances were used to refinance $400 million of two-year floating rate notes that matured on February 8, 2002, which had been issued to finance SCANA's acquisition of PSNC. On January 31, 2002 SCE&G issued $300 million of first mortgage bonds having an annual interest rate of 6.625 percent and maturing February 1, 2032. The proceeds from the sale of these bonds were used to reduce short-term debt primarily incurred as a result of SCE&G's construction program and to redeem its First and Refunding Mortgage Bonds, 8 7/8 percent Series due August 15, 2021. 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 17, 2002. 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. Fuel Company commercial paper outstanding totaled $50.1 million and $70.2 million at December 31, 2001 and 2000, respectively, at weighted average interest rates of 2.06 percent and 6.59 percent, respectively. 8. SHORT-TERM BORROWINGS Details of lines of credit (including uncommitted lines of credit) and short-term borrowings at December 31, 2001 and 2000, are as follows: Millions of dollars 2001 2000 --------------------------------------------------------- --------------- Authorized lines of credit $588.0 $649.0 Unused lines of credit $588.0 $564.0 Short-term borrowings outstanding Bank loans - $85.0 Weighted average interest rate n/a 7.48% Commercial paper (270 days or less) $164.8 $312.7 Weighted average interest rate 1.97% 6.63% The Company pays fees to banks as compensation for its committed lines of credit. 9. COMMON EQUITY The Company's Restated Articles of Incorporation 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, 2001 approximately $37 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 2001, 2000 and 1999 at an annual rate per share of $1.20, $1.15 and $1.32, respectively. The accumulated balances related to each component of other comprehensive income were as follows: Unrealized Cash flow Accumulated other -------------------------------- ains (losses) hedging comprehensive -------------------------------- Million of dollars on securities activities income -------------------------------------------------------------------------------- -------------------------------- Balance, January 1, 1999 $25 $25 -------------------------------- Other comprehensive income 311 311 -------------------------------------------------------------------------------- Balance, December 31, 1999 336 336 -------------------------------- Other comprehensive loss (197) (197) -------------------------------------------------------------------------------- Balance, December 31, 2000 139 139 -------------------------------- Other comprehensive loss (226) $(26) (252) -------------------------------- -------------------------------------------------------------------------------- Balance, December 31, 2001 $(87) $(26) $(113) ================================================================================ 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 2002 through 2006 is $2.8 million. The changes in "Total Preferred Stock (Subject to purchase or sinking funds)" during 2001, 2000 and 1999 are summarized as follows: Number of Shares Millions of Dollars ------------------------------------------------------------------------------- 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 Shares Redeemed - $50 par value (10,803) (0.5) ------------------------------------------------------------------------------- Balance at December 31, 2001 209,484 $10.5 =============================================================================== 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. The financial statements of the Trust are consolidated in the financial statements of SCE&G. 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 2001, 2000 and 1999 is as follows: Millions of dollars 2001 2000 1999 ------------------------------------------------------------------- ----------------- ----------------- ----------------- Current taxes: Federal $91.2 $88.2 $94.5 State 11.2 9.2 0.6 ------------------------------------------------------------------- ----------------- ----------------- ----------------- ------------------------------------------------------------------- ----------------- ----------------- ----------------- Total current taxes 102.4 97.4 95.1 ------------------------------------------------------------------- ----------------- ----------------- ----------------- ------------------------------------------------------------------- ----------------- ----------------- ----------------- Deferred taxes, net: Federal 182.5 29.8 6.1 State 1.7 4.7 1.5 ------------------------------------------------------------------- ----------------- ----------------- ----------------- ------------------------------------------------------------------- ----------------- ----------------- ----------------- Total deferred taxes 184.2 34.5 7.6 ------------------------------------------------------------------- ----------------- ----------------- ----------------- ------------------------------------------------------------------- ----------------- ----------------- ----------------- Investment tax credits: Deferred - State 5.0 5.0 13.4 Amortization of amounts deferred - State (1.5) (1.3) (1.2) Amortization of amounts deferred - Federal (4.0) (4.0) (3.6) ------------------------------------------------------------------- ----------------- ----------------- ----------------- Total investment tax credits (0.5) (0.3) 8.6 ------------------------------------------------------------------- ----------------- ----------------- ----------------- Non-conventional fuel tax credits: Deferred - Federal 18.7 9.4 n/a ------------------------------------------------------------------- ----------------- ------------------ ---------------- Total income tax expense $304.8 $141.0 $111.3 =================================================================== ================= ================== ================

The difference between actual income tax expense and the amount calculated from the application of the statutory 35 percent Federal income tax rate to pre-tax income (before cumulative effect of accounting change) is reconciled as follows:

Millions of dollars 2001 2000 1999 ------------------------------------------------------------------- ----------------- ------------------ ---------------- Income before cumulative effect of accounting change $539.3 $221.2 $178.9 Total income tax expense: Charged to operating expense 135.2 152.0 112.9 Charged (credited) to other items 169.7 (11.0) (1.6) Preferred stock dividends 11.2 11.2 11.2 ------------------------------------------------------------------- ----------------- ------------------ ---------------- ------------------------------------------------------------------- ----------------- ------------------ ---------------- Total pre-tax income $855.4 $373.4 $301.4 =================================================================== ================= ================== ================ =================================================================== ================= ================== ================ Income taxes on above at statutory Federal income tax rate $299.4 $130.7 $105.5 Increases (decreases) attributed to: State income taxes (less Federal income tax effect) 10.7 11.4 9.3 Non-deductible book amortization of acquisition adjustments 5.0 5.0 0.4 Amortization of Federal investment tax credits (4.0) (4.0) (3.6) Other differences, net (6.3) (2.1) (0.3) ------------------------------------------------------------------- ----------------- ------------------ ---------------- ------------------------------------------------------------------- ----------------- ------------------ ---------------- Total income tax expense $304.8 $141.0 $111.3 =================================================================== ================= ================== ================

The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $873.9 million at December 31, 2001 and $819.2 million at December 31, 2000 (see Note 1I), are as follows: Millions of dollars 2001 2000 ------------------------------------------------------ ------------------ Deferred tax assets: Nondeductible reserves $69.7 $59.3 Unamortized investment tax credits 62.1 63.0 Deferred compensation 23.1 23.4 Cycle billing 10.6 - Other 14.4 8.7 ------------------------------------------------------ ------------------ Total deferred tax assets 179.9 154.4 ------------------------------------------------------ ------------------ Deferred tax liabilities: Property, plant and equipment 814.3 792.3 Investments in equity securities 133.3 80.0 Pension plan benefit income 81.1 65.3 Deferred fuel costs 22.8 18.5 Cycle billing - 1.9 Other 2.3 15.6 ------------------------------------------------------ ------------------ Total deferred tax liabilities 1,053.8 973.6 ------------------------------------------------------ ------------------ Net deferred tax liability $873.9 $819.2 ====================================================== ================== 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, 1999 and 2000. 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, 2001 and 2000 are as follows: Millions of dollars 2001 2000 -------------------------------------------------------------------------- Estimated Estimated Carrying Fair Carrying Fair Amount Value Amount Value -------------------------------------------------------------------------------- Assets: Cash and temporary cash investments $212.0 $212.0 $158.7 $158.7 Investments 855.1 944.3 681.7 1,234.5 Liabilities: Short-term borrowings 164.8 164.8 397.7 397.7 Long-term debt 3,384.8 3,501.0 2,890.5 2,931.9 Preferred stock (subject to purchase or sinking funds) 10.4 8.5 11.0 8.7 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 is considered to approximate carrying value. The carrying values reflect the fair values of interest rate swaps based on settlement values obtained from counterparties. 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. Investments SCANA and certain of its subsidiaries hold investments in marketable securities, some of which are subject to SFAS 115 mark-to-market accounting and some of which are considered cost basis investments for which determination of fair value historically has been considered impracticable. Equity holdings subject to SFAS 115 are categorized as "available for sale" and are carried at quoted market, with any unrealized gains and losses credited or charged to other comprehensive income within common equity on the Company's balance sheet. Debt securities are categorized as "held to maturity" and are carried at amortized cost. When indicated, and in accordance with its stated accounting policy, SCANA performs periodic assessments of whether any decline in the value of these securities to amounts below SCANA's cost basis is other than temporary. When other than temporary declines occur, write-downs are recorded through operations, and new (lower) cost bases are established. At December 31, 2001 SCANA and SCANA Communications Holdings, Inc. (SCH), a wholly owned, indirect subsidiary of SCANA, held marketable equity and debt securities in the following companies in the amounts noted in the table below.

Unrealized Investee Held By Securities (a) Basis Market (b) Gain/(Loss) (c) ------------------------------ --------------------------------------------------------- ---------- ------------ ---------------- (Millions of dollars) DTAG SCH 39.3 million ordinary shares $798.0 $664.3 ($133.7) ITC SCH 3.1 million common stock 5.8 (d) n/a SCH 645,153 series A convertible preferred stock 7.2 (d) n/a SCH 133,664 series B convertible preferred stock 4.0 (d) n/a ITC^DeltaCom SCH 5.1 million common stock 4.4 (e) 4.4 - SCH 1.5 million series A convertible preferred stock, convertible March 2002 2.6 (e) 2.6 - SCANA 5,113 series B-1 preferred stock convertible into 877,193 shares of common stock 0.8 (e) 0.8 - SCANA 6,667 series B-2 preferred stock convertible into 2,604,297 shares of common stock 2.3 (e) 2.3 - SCANA Warrants to purchase approximately 1.0 million shares of common stock 0.8 (e) 0.8 - Knology SCH 7.2 million series A preferred stock, convertible 5.0 (d) n/a upon an initial public offering SCH Warrants to purchase 159,000 shares of series A convertible preferred stock, convertible upon an initial public (d) n/a offering SCH 8.3 million series C preferred stock, convertible 25.0 (d) n/a upon an initial public offering Knology Broadband SCH $71,050,000 face amount, 11.875% Senior Discount Notes due 2007 64.9 (d) n/a

(a) Convertible preferred stock is convertible into common stock at any time nless otherwise indicated. (b) As converted, based on market value of underlying common stock, where applicable. (c) Amounts are included in accumulated other comprehensive income (loss), net of taxes. (d) Market value not readily determinable. (e) Reflects write-down for "other than temporary" impairment as discussed below. Deutsche Telekom AG (DTAG) is an international telecommunications carrier. The Company's investment in DTAG was received in exchange for approximately 14.9 million shares of Powertel, Inc. (Powertel) which SCH owned prior to DTAG's acquisition of Powertel in May 2001. SCH recorded a non-cash, after-tax gain of $354.4 million as a result of the exchange. ITC Holding Company (ITC) holds ownership interests in several Southeastern communications companies. ITC^DeltaCom, Inc. (ITCD) is a fiber optic telecommunications provider and an affiliate of ITC. Knology, Inc. (Knology) is a broadband service provider of cable television, telephone and internet services. Knology is an affiliate of ITC. Knology Broadband, Inc. (Knology Broadband) is a wholly-owned subsidiary of Knology and an affiliate of ITC. In the fourth quarter of 2001 the Company determined that the decline in value of its investment in ITC^DeltaCom (to below cost) was other than temporary. Accordingly the Company recorded an impairment charge of approximately $35.0 million (after-tax). Derivatives Through December 31, 2000 the Company accounted for the results of its derivative activities for hedging purposes in accordance with SFAS 80. Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. SFAS 133 requires the Company to recognize all derivative instruments as either assets or liabilities in the statement of financial position and to measure those instruments at fair value. SFAS 133 further provides that changes in the fair value of derivative instruments are either recognized in earnings or reported as a component of other comprehensive income, depending upon the intended use of the derivative and the resulting designation. The fair value of the derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or quotations from independent parties. Risk limits are established to control the level of market, credit, liquidity and operational/administrative risks assumed by the Company. The Company's Board of Directors has delegated the authority for setting market risk limits to the Risk Management Committee, which is comprised of members of senior management, the Company's Controller, the Senior Vice President of SCPC and the President of SCANA Energy Marketing, Inc. The Risk Management Committee provides assurance to the Board of Directors with regard to compliance with risk management policies and brings to the Board's attention any areas of concern. Written policies define the physical and financial transactions that are approved as well as the authorization requirements and limits for those transactions that are allowed. Commodities The Company uses derivative instruments to hedge anticipated future purchases of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile price market and risks associated with price differentials at different delivery locations. The basic types of financial instruments utilized are exchange-traded instruments, such as New York Mercantile Exchange futures contracts or options and over-the-counter instruments such as swaps, which are typically offered by energy and financial institutions. 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. Substantially all of this amount was reclassified into earnings in 2001 as a component of gas cost. The Company recognized losses of approximately $(17.1) million, net of tax (net of the gains discussed above), as a result of qualifying cash flow hedges whose hedged transactions occurred during the year ended December 31, 2001. These losses were recorded in cost of gas. Losses due to hedge ineffectiveness were insignificant. The Company estimates that substantially all of the December 31, 2001 balance of $(26) million, net of tax, will be reclassified from accumulated other comprehensive income to earnings in 2002 as increased gas cost. As of December 31, 2001, all of the Company's cash flow hedges would be settled before the end of 2003. Certain derivatives that SCPC utilizes to hedge its gas purchasing activities are recoverable through its fuel adjustment clauses. Accordingly, the offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. The Company also utilizes certain derivative instruments that do not qualify as hedges. The change in fair value of these derivatives is recorded in net income, and was insignificant in 2001. Interest Rates In May 2001 the Company entered into an interest rate swap agreement to pay variable rate and receive fixed rate interest payments on a notional amount of $300 million. This swap was designated as a fair value hedge of the $300 million medium-term notes also issued in May. The swap agreement was terminated and replaced with another swap agreement to pay variable rate and receive fixed rate interest payments, also designated as a fair value hedge, in August 2001. At December 31, 2001 the estimated fair value of this swap was $1.3 million. In August 2001 the Company received $6.5 million to terminate the original swap. This amount is being amortized to interest expense over the ten year term of the $300 million medium-term notes. On December 19, 2001 PSNC entered into two interest rate swap agreements to pay variable rate and receive fixed rate interest payments on a combined notional amount of $44.9 million. These swaps were designated as fair value hedges of PSNC's $12.9 million, 10 percent senior debenture due 2004 and $32.0 million, 8.75 percent senior debenture due 2012. The fair value of these interest rate swaps is reflected within other deferred debits on the balance sheet. The corresponding hedge debt is also marked to market on the balance sheet. The receipts or payments related to the interest rate swaps are credited or charged to interest expense as incurred. 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. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost $250 million and be completed in 2005. Any costs incurred by SCE&G are expected to be recoverable through electric rates. 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 costs, 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 $14.1 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 would 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, among others, of its 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 various industrial operations, including one of SCE&G's decommissioned MGPs. Field work at the site began in November 1993 and has required the submission of several investigative reports and the implementation of several work plans. In September 2000, SCE&G was notified by the South Carolina Department of Health and Environmental Control (DHEC) that benzene contamination was detected in the intermediate aquifer on surrounding properties of the Calhoun Park area site. The EPA required that SCE&G conduct a focused Remedial Investigation/Feasibility Study on the intermediate aquifer, which was completed in June 2001. The EPA expects to issue a Record of Decision dealing with the intermediate aquifer and sediments in June 2002. SCE&G anticipates that major remediation activities will be completed in 2003, with certain monitoring activities continuing until 2007. As of December 31, 2001, SCE&G has spent approximately $15.8 million to remediate the Calhoun Park area site. Total remediation costs are estimated to be $21.9 million. SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by DHEC. SCE&G is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. SCE&G anticipates that major remediation activities for these three sites will be completed between 2003-2005. SCE&G has spent approximately $2.0 million related to these sites, and expects to incur an additional $6.0 million. 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 two sites 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. PSNC estimates that the cost to remediate the sites would range between $11.3 million and $21.9 million. 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. At December 31, 2001 PSNC has recorded a liability and associated regulatory asset of $9.1 million, which reflects the minimum amount of the range, net of shared cost recovery expected from other PRPs and expenditures for work completed. Amounts incurred to date are approximately $1.1 million. Management believes that all MGP cleanup costs incurred will be recoverable through 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 In 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. F. Operating Lease Commitments The Company is obligated under various operating leases with respect to office space, furniture and equipment. Leases expire at various dates through 2011. Rent expense totaled approximately $12.1 million, $8.8 million and $6.7 million in 2001, 2000 and 1999, respectively. Future minimum rental payments under such leases are as follows: Millions of dollars 2002 $17.2 2003 14.7 2004 11.4 2005 10.3 2006 9.7 Thereafter 26.5 ------ $89.8 G. Purchase Commitments Purchase commitments including those commitments under forward contracts for natural gas purchases, gas transportation capacity agreements and coal supply contracts are as follows: Millions of dollars 2002 $508.6 2003 216.4 2004 73.0 2005 15.3 2006 15.3 Thereafter 196.6 ----- $1,025.2 The forward contracts for natural gas purchases include customary "make-whole" or default provisions, but are not considered to be "take-or-pay" contracts. 14. SEGMENT OF BUSINESS INFORMATION The Company's reportable segments are Electric Operations, Gas Distribution, Gas Transmission, Retail Gas Marketing, Energy Marketing and Telecommunications Investments. 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. Nonregulated 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 SCPSC. 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 33 counties in South Carolina covering approximately 22,000 square miles. PSNC was acquired by SCANA in 2000. PSNC's operations cover 26 counties in North Carolina and approximately 12,000 square miles. Gas Transmission is comprised of SCPC, 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. SCPC also owns LNG liquefaction and storage facilities. Both of these segments are regulated in their respective states of operations. Retail Gas Marketing markets natural gas in Georgia's deregulated natural gas market. Energy Marketing markets electricity and natural gas to industrial, large commercial and wholesale customers, primarily in the Southeast. Telecommunications Investments holds investments in telecommunication companies. 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 nonregulated, but differ from each other primarily based on their respective markets. Disclosure of Reportable Segments

Millions of dollars ---------------------------- ---------- ----------- ------------- --------- --------------------------- ----- ------------ --------- Electric Gas Gas Retail Energy Telecommunications All Adjustments/ Consolidated Gas 2001 Operations DistributionTransmission Marketing Marketing Investments Other Eliminations Total ---------------------------- ---------- ----------- ------------- --------- --------------------------- ----- ------------ --------- External Customer Revenue $1,369 $789 $226 $628 $439 - $(49) $3,451 $49 Intersegment Revenue 576 4 253 - - - (841) - 8 Operating Income 419 75 16 n/a n/a - (4) 528 22 Interest Expense 10 22 6 6 3 $23 151 223 2 Depreciation & Amortization 160 54 7 2 1 - (6) 224 6 Income Tax Expense 3 18 4 4 1 169 102 305 4 Net Income n/a n/a n/a 8 3 314 240 539 (26) Segment Assets 5,034 1,617 335 99 96 784 272 (415) 7,822 Expenditures for Assets 414 90 21 4 2 - - 548 17 Deferred Tax Assets 6 - 4 5 6 - (21) - - ---------------------------- ---------- ----------- ------------- --------- --------------------------- ----- ------------ ---- Millions of dollars ---------------------------- ---------- ----------- ------------- --------- --------------------------- ------ ------------- ------- Electric Gas Gas Retail Energy Telecommunications All Adjustments/ Consolidated Gas 2000 Operations DistributionTransmission Marketing Marketing Investments 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 $23 3 156 225 Depreciation & Amortization 155 53 7 1 - - 5 (4) 217 Income Tax Expense 1 23 8 1 (1) (4) - 113 141 (Benefit) Net Income (Loss) n/a n/a 4 (4) (7) 1 256 250 n/a Segment Assets 4,953 1,628 309 103 215 599 86 (466) 7,427 Expenditures for Assets 229 58 18 - - - 27 29 361 Deferred Tax Assets 6 - 3 5 4 - 1 (19) - ---------------------------- ---------- ----------- ------------- --------- --------------------------- ------ ------------- ------- Millions of dollars ---------------------------- ---------- ----------- ------------ --------- -------------------------------- ------------------------ Electric Gas Gas Retail Energy Telecommunications All Adjustments/ Consolidated Gas 1999 Operations DistributionTransmission Marketing Marketing Investments 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 $1 22 98 142 Depreciation & Amortization 148 13 7 1 1 - 7 (8) 169 Income Tax Expense 1 n/a 9 (24) (2) - 21 106 111 (Benefit) Net Income (Loss) n/a n/a n/a (45) (4) - 22 206 179 Segment Assets 4,751 399 253 (24) 168 889 43 (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 ---------------------------- ---------- ----------- ------------ --------- --------------------------- ----- ------------ ----------

Revenues and assets from segments below the quantitative thresholds are attributable to SCE&G's transit operations, which are regulated by the SCPSC, and to ten other wholly owned subsidiaries of the Company. These subsidiaries conduct nonregulated operations in energy-related and telecommunications industries. None of these subsidiaries met any of the quantitative thresholds for determining reportable segments in 2001, 2000 or 1999. Management uses operating income to measure segment profitability for regulated operations. For nonregulated 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 cumulative effect of the accounting change described in Note 2. The Consolidated Financial Statements report operating revenues which are comprised of the energy-related reportable segments. Revenues from non-reportable segments and investment income from Telecommunications Investments 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. Segment assets include utility plant only (excluding accumulated depreciation) for SCE&G's Electric Operations, Gas Distribution and Transit Operations, and all assets for PSNC and the remaining segments. As a result, adjustments to assets include accumulated depreciation, common and non-utility plant and non-fixed assets for SCE&G. Adjustments to Interest Expense, Income Tax Expense (Benefit), Deferred Tax Assets and Expenditures for 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. Expenditures for Assets are also adjusted for AFC. 15. QUARTERLY FINANCIAL DATA (UNAUDITED)

(Millions of dollars, except per share amounts) 2001 First Second Third Fourth Quarter Quarter Quarter Quarter Annual --------------------------------------------------- ------------ ------------- -------------- ----------- Total operating revenues $1,318 $740 $710 $683 $3,451 Operating income 173 93 143 119 528 Net income 79 385 63 12 539 Basic and diluted earnings per share .75 3.67 .61 .12 5.15

----------------------------------------------------- ------------ ------------- -------------- ----------- 2000 First Second Third Fourth Quarter Quarter Quarter Quarter Annual ----------------------------------------------------- ------------ ------------- -------------- ----------- Total operating revenues $821 $662 $816 $1,134 $3,433 Operating income 172 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

16. SUBSEQUENT EVENT On March 1, 2002, the Company determined that the decline in value of its investment in DTAG to below its cost basis of $20.30 per share was other than temporary, and recorded an impairment loss of approximately $160 million (after tax). SOUTH CAROLINA ELECTRIC & GAS COMPANY Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................................. 81 Item 7A. Quantitative and Qualitative Disclosures About Market Risk..... 92 Item 8. Financial Statements and Supplementary Data.................... 93 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 Electric Operations After the energy supply and pricing problems experienced in California in 2000 and 2001, the efforts to restructure electric markets at the state level have slowed considerably. Many states that had considered legislation to restructure the electric industry have stopped such efforts or are proceeding more slowly. In South Carolina electric restructuring efforts remain stalled, and consideration of electric restructuring legislation is unlikely in 2002. Further, while several companies have announced their intent to site merchant generating plants in SCE&G's service territory, economic events, environmental concerns and other factors have slowed those efforts. Legislation or regulatory action at the Federal level, particularly as part of a larger energy policy initiative, may be considered in 2002. 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 increased significantly, and SCE&G has executed 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. LIQUIDITY AND CAPITAL RESOURCES SCE&G's cash requirements 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, SCE&G expects to seek increases in rates. 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 estimated primary cash requirements for 2002 and the actual primary cash requirements for 2001, excluding requirements for non-nuclear fuel purchases, short-term borrowings and dividends, and including notes payable to affiliated companies, are as follows: Millions of dollars 2002 2001 ------------------------------------------------------------- --------------- Property additions and construction expenditures, net of AFC $506 $425 Nuclear fuel expenditures 6 4 Investments 11 7 Maturing obligations, redemptions and sinking and purchase fund requirements 5 5 ---------------------------------------------------------------- --------------- Total $528 $441 ================================================================ =============== Approximately 68 percent of total cash requirements was provided from internal sources in 2001 as compared to 63 percent in 2000. For the years 2003-2006, SCE&G has an aggregate of $578.4 million of long-term debt and preferred stock maturing, which includes an aggregate of $576.2 million for debt and $2.2 million of purchase or sinking fund requirements for SCE&G's preferred stock. SCE&G's long-term debt maturities for the years 2003-2006 include approximately $93.8 million for sinking fund requirements all of which may be satisfied by deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits. These obligations and other commitments are tabulated below. Contractual Cash Obligations Less than After December 31, 2001 Total 1year 1-3 years 4-5 years 5 years ----------------- ----- ----- --------- --------- ------- (Millions of dollars) Long-term and short-term debt (including interest) $2,887 $275 $634 $275 $1,703 Preferred stock sinking funds 11 1 2 1 7 Operating leases 78 12 31 18 17 Other commercial commitments 381 167 203 1 10 Included in other commercial commitments are estimated obligations for coal supply purchases. Actual purchases are included in fuel used in electric generation and recovered through electric rates. SCE&G anticipates that its contractual cash obligations will be met through internally generated funds 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 foreseeable future. Financing Limits and Related Matters SCE&G's issuance of various securities including long-term and short-term debt is subject to customary approval or authorization by state and Federal regulatory bodies including SCPSC, the SEC and FERC. The following paragraphs describe the financing programs currently utilized by SCE&G. 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, 2001 the Bond Ratio was 5.77. The Old Mortgage allows the issuance of additional Class A Bonds up to an additional principal amount equal to (i) 70 percent of unfunded net property additions (which unfunded net property additions totaled approximately $1,759 million at December 31, 2001), (ii) retirements of Class A Bonds (which retirement credits totaled $44.9 million at December 31, 2001), and (iii) cash on deposit with the Trustee. SCE&G is also 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. 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, 2001 the New Bond Ratio was 5.71. SCE&G's Restated Articles of Incorporation prohibit issuance of additional shares of preferred stock without the consent of the preferred shareholders 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 on all shares of preferred stock outstanding immediately after the proposed issue (Preferred Stock Ratio). For the year ended December 31, 2001 the Preferred Stock Ratio was 1.83. 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. At December 31, 2001 SCE&G had $250 million of unused authorized lines of credit under a credit agreement supporting the issuance of commercial paper. SCE&G's commercial paper outstanding at December 31, 2001 and 2000 was $114.7 million and $117.5 million, respectively. In addition, Fuel Company has a credit agreement for a maximum of $125 million with the full amount available at December 31, 2001. 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, 2001 and 2000 was $50.1 million and $70.2 million, respectively. This commercial paper and amounts outstanding under the revolving credit agreement, if any, are guaranteed by SCE&G. Financing Transactions and Other Information The following financing transactions have occurred since January 1, 2001: o On January 24, 2001 SCE&G issued $150 million of 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 January 31, 2002 SCE&G issued $300 million of first mortgage bonds having an annual interest rate of 6.625 percent and maturing February 1, 2032. The proceeds from the sale of these bonds were used to reduce short-term debt primarily incurred as a result of SCE&G's construction program and to redeem its First and Refunding Mortgage Bonds, 8 7/8 percent Series due August 15, 2021. SCE&G is constructing 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. In October 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. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost $250 million and be completed in 2005. Any costs incurred by SCE&G are expected to be recoverable through electric rates. In October 2001 SCE&G filed with the SCPSC its siting plans to construct an 875 megawatt generation facility in Jasper County, South Carolina, to supply electricity to its South Carolina customers. The facility will include three natural gas combustion-turbine generators and one steam-turbine generator. Construction of the $450 million facility is expected to begin in April 2002, with commercial operation in the summer of 2004. In connection with the facility, SCE&G has signed a 250 megawatt electric supply contract with North Carolina Electric Membership Corporation for a term of at least nine years beginning January 1, 2004. ENVIRONMENTAL MATTERS Electric Operations The Clean Air Act Amendment of 1990 (CAA) required electric utilities to reduce emissions of sulfur dioxide and nitrogen oxides (NOx) substantially by the year 2000. SCE&G's compliance with these reductions has been accomplished. The EPA has indicated that it will propose regulations by December 2003 for stricter limits on mercury and other toxic pollutants generated by coal-fired plants. SCE&G currently estimates that air emissions control equipment will require capital expenditures of $72 million over the 2002-2006 period to retrofit existing facilities, with increased operation and maintenance costs of approximately $1.2 million per year. To meet compliance requirements for the years 2007 through 2011, SCE&G anticipates additional capital expenditures of approximately $6 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. While not final, South Carolina has proposed NOx reductions that would require SCE&G to install pollution control equipment to reduce its NOx emissions. Capital expenditures will be required to comply with the NOx reductions and they are included in the cost figures above. The EPA has undertaken an aggressive enforcement initiative against the industry and the Department of Justice 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. The basis for these suits is the assertion 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 Canadys and Wateree Stations. The regulations under the CAA provide certain exemptions to the definition of "major modifications," including an exemption for routine repair, replacement or maintenance. SCE&G has analyzed each of the activities covered by the EPA's requests and believes that each of these activities is covered by the exemption for routine repair, replacement and maintenance. The regulations also provide an exemption for an increase in emissions resulting from increased hours of operation or production rate and from demand growth. It is possible that the EPA will commence enforcement actions against SCE&G, and the EPA has the authority to seek penalties at the rate of up to $27,500 per day for each violation. The EPA also could seek installation of BACT (or equivalent) at the two plants. SCE&G believes that any assertions relative to SCE&G's compliance with the CAA would be without merit. However, if successful, such assertions could have a material adverse effect on SCE&G's financial position, cash flows and results of operations. The Federal Clean Water Act, as amended, provides for the imposition of effluent limitations that require treatment for wastewater discharges. 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. Gas Distribution SCE&G maintains an environmental assessment program to identify and evaluate 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 to regulated operations and are deferred and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.4 million and $20.2 million at December 31, 2001 and 2000, respectively. The deferral includes the estimated costs associated with the following matters. o In September 1992 the EPA notified SCE&G, among others, of its 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 various industrial operations, including one of SCE&G's decommissioned MGPs. Field work at the site began in November 1993 and has required the submission of several investigative reports and the implementation of several work plans. In September 2000, SCE&G was notified by the South Carolina Department of Health and Environmental Control (DHEC) that benzene contamination was detected in the intermediate aquifer on surrounding properties of the Calhoun Park area site. The EPA required that SCE&G conduct a focused Remedial Investigation/Feasibility Study on the intermediate aquifer, which was completed in June 2001. The EPA expects to issue a Record of Decision dealing with the intermediate aquifer and sediments in June 2002. SCE&G anticipates that major remediation activities will be completed in 2003, with certain monitoring activities continuing until 2007. As of December 31, 2001, SCE&G has spent approximately $15.8 million to remediate the Calhoun Park area site. Total remediation costs are estimated to be $21.9 million. o SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by DHEC. SCE&G is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. SCE&G anticipates that major remediation activities for these three sites will be completed between 2003-2005. SCE&G has spent approximately $2.0 million related to these sites, and expects to incur an additional $6.0 million. REGULATORY MATTERS - STATE 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 $217 million and $81 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities of approximately $125 million and $71 million, respectively, on its balance sheet at December 31, 2001. SCE&G's generation assets would be 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, 2001, SCE&G's net investment in fossil/hydro and nuclear generation assets was $1,385.5 million and $572.9 million, respectively. SCE&G is subject to the jurisdiction of the SCPSC as to retail electric, gas and transit rates, service, accounting, issuance of securities (other than short-term promissory notes) and other matters. Electric On April 24, 2001 the SCPSC approved SCE&G's request to increase the fuel component of rates charged to electric customers from 1.330 cents per kilowatt-hour to 1.579 cents per kilowatt-hour. The increase reflects higher fuel costs projected for the period May 2001 through April 2002. The increase also provides recovery over a two-year period of under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of SCE&G's base load generating plants in winter 2000-2001. The new rates were effective as of the first billing cycle in May 2001. On September 14, 1999 the SCPSC 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 SCPSC 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 SCPSC. 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, 2001 no accelerated depreciation has been recorded. The accelerated capital recovery plan will be accomplished through existing customer rates. On January 9, 1996 the SCPSC authorized a return on common equity of 12.0 percent. The SCPSC 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 SCPSC approved accelerated amortization 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, which enabled SCE&G to recover the balances as of the end of the year 2000. Gas SCE&G's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by SCE&G. SCE&G's cost of gas component in effect during the years ended December 31, 2001 and 2000 was as follows: Rate Per Therm Effective Date Rate Per Therm Effective Date $.993 January-February 2001 $.543 January-July 2000 $.793 March-October 2001 $.688 August-October 2000 $.596 November-December 2001 $.782 November-December 2000 On July 5, 2000 the SCPSC 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. The retroactive effect was recorded in the second quarter of 2000. In 1994 the SCPSC 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 October 2001, as a result of the annual review, the SCPSC approved SCE&G's request to increase the billing surcharge from 1.1cents per therm to 3.0 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2005, of the balance remaining at December 31, 2001 of $24.4 million. Transit In September 1992 the SCPSC 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 SCPSC also required $.40 fares for low income customers and denied SCE&G's request for certain bus route and schedule changes. The new rates were placed into effect in October 1992. After several appeals and petitions for reconsideration to the Circuit Court and the Supreme Court by the various parties, on September 27, 2000 the SCPSC issued an order granting certain relief requested by SCE&G. On September 29, 2000 the Consumer Advocate filed a motion with the SCPSC for a stay of this order. On October 3, 2000 the SCPSC 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 SCPSC's order granting relief. The Circuit Court has held in abeyance any appellate review pending the outcome of current negotiations on the transfer of the transit system from SCE&G to an unaffiliated regional transit authority. REGULATORY MATTERS - FEDERAL SCE&G's regulated business operations were impacted by FERC Orders No. 636, 888 and 2000. 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 SCE&G, 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. As already noted, Order No. 2000 required utilities which operate electric transmission systems to submit plans for the possible formation of RTOs. In March 2001 FERC gave provisional approval to SCE&G and two other southeastern electric utilities to establish GridSouth Transco, LLC (GridSouth) as an independent regional transmission company, responsible for operating and planning the utilities' combined transmission systems. In July 2001 FERC expressed its desire that utilities throughout the United States combine their transmission systems to create four large independent regional operators, one each in the Northeast, Southeast, Midwest and West. Accordingly, FERC ordered mediation talks to take place between the utilities forming GridSouth and certain groups that had proposed other RTOs. These talks were mediated by an administrative law judge, who issued her nonbinding mediation report to FERC in September 2001. The report made recommendations related to the formation of a Southeast regional RTO. While FERC has not acted on the mediation report, and the timing or impact of future FERC orders related to RTOs cannot be predicted, SCE&G expects to be reimbursed or to otherwise recover costs it has incurred in connection with RTO formation. CRITICAL ACCOUNTING POLICIES AND NEW ACCOUNTING STANDARDS Following are descriptions of SCE&G's accounting policies which are new or most critical in terms of reporting results of operations. SFAS 71 - SCE&G is subject to the provisions of SFAS 71, which requires it to record certain assets and liabilities that defer the recognition of expenses and revenues to future periods as a result of being rate-regulated. Aside from other impacts which might be experienced as a result of deregulation or other significant changes in the regulatory environments of the utilities, SFAS 71 could cease to be applicable and SCE&G could be required to write off such regulatory assets and liabilities (see also COMPETITION). Provisions for bad debts / Allowances for doubtful accounts - As of each balance sheet date, SCE&G evaluates the collectibility of accounts receivable and records allowances for doubtful accounts based on estimates of the level of actual write-offs which might be experienced. These estimates are based on, among other things, comparisons of the relative age of accounts and consideration of actual write-off history. Pension accounting - SCE&G follows SFAS 87 in accounting for its defined benefit pension plan. SCE&G's plan is well funded and as such, significant net pension income is reflected in the financial statements (see Result's of Operations). SFAS 87 requires the use of several assumptions, the selection of which may have a large impact on the resulting benefit recorded. Among the more sensitive assumptions are those surrounding discount rates and returns on assets. Net pension income of $41.1 million recorded in 2001 reflects the use of an 8 percent discount rate and an assumed 9.5 percent long-term return on plan assets. SCE&G believes that these assumptions are, and that the resulting pension income amount is, reasonable. Were SCE&G to have alternatively selected a discount rate of 7.5 percent and a rate of return on assets of 9 percent, the net pension income recorded in 2001 would have been reduced by approximately $5.9 million. Accounting for postretirement benefits other than pensions - Similar to its pension accounting, SCE&G follows SFAS 106 in accounting for its postretirement medical and life insurance benefits. This plan is unfunded, so no return on assets impacts the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. SCE&G used a discount rate of 8 percent and recorded a net SFAS 106 cost of $14.4 million for 2001. Were the selected discount rate to have been 7.5 percent, the expense would have been approximately $0.4 million higher. SFAS 143, "Accounting for Asset Retirement Obligations, provides guidance for recording and disclosing a liability related to the future obligation to retire an asset (such as a nuclear plant). SCE&G will adopt SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on SCE&G's results of operations, cash flows or financial position has not been determined but could be material. The provisions of SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," are effective January 1, 2002. This Statement requires that one accounting model be used for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired, and broadens the presentation of discontinued operations to include more disposal transactions. There was no impact on SCE&G's financial statements from the initial adoption of SFAS 144. AFFILIATE TRANSACTIONS SCE&G has two equity-method investments in partnerships involved in converting coal to alternate fuel, the use of which fuel qualifies for favorable Federal income tax treatment (tax credits). The aggregate investment in these partnerships as of December 31, 2001 is approximately $3 million, and through December 31, 2001, they had generated and passed through to SCE&G approximately $28 million in such tax credits. Under a plan approved by the SCPSC, any tax credits generated and ultimately passed through to SCE&G have been and will be deferred and used to offset defined capital expenditures such as those related to reduction of environmental emissions. OTHER MATTERS Claims and Litigation SCANA and Westvaco each own a 50 percent interest in Cogen South LLC (Cogen). Cogen built and operates a cogeneration facility in North Charleston, South Carolina. On September 10, 1998 the contractor in charge of construction filed suit in Circuit Court 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 named as defendants in the suit. Cogen filed a separate suit against the contractor for delay and performance issues. The suits were combined and the contractor brought the manufacturer of the generator into the performance suit. In November 2001 a settlement was reached between all parties. Terms of the settlement are confidential, but the settlement's impact on SCE&G's results of operations, cash flow and financial position is not material. SCE&G is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to SCE&G. RESULTS OF OPERATIONS Net Income Net income and the percent change from the previous year for the years 2001, 2000 and 1999 were as follows: Millions of dollars 2001 2000 1999 ------------------------------------------------------------------------------ Net income derived from: Continuing operations $221.9 $231.3 $189.2 Cumulative effect of accounting change, net of taxes - 22.3 - ------------------------------------------------------------------------------ Net income $221.9 $253.6 $189.2 ============================================================================== Percent increase (decrease) in net income (12.50%) 34.04% (16.75%) ============================================================================== o 2001 vs 2000 Net income decreased primarily as a result of milder weather and a slowing economy. 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. Pension income recorded by SCE&G reduced operations expense by $20.6 million, $20.9 million and $16.3 million for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, pension income increased other income by $12.7 million, $12.9 million and $10.5 million for the years ended December 31, 2001, 2000 and 1999, respectively. 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 the recording of an AFC. AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. An equity portion of AFC is included in nonoperating income and a debt portion of AFC is included in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 6.5 percent of income before income taxes in 2001, 1.7 percent in 2000 and 2.0 percent in 1999. Electric Operations Electric Operations is comprised of the electric portion of SCE&G and Fuel Company. Electric operations sales margins, for 2001, 2000 and 1999, excluding the cumulative effect of accounting change in 2000, were as follows: Millions of dollars 2001 2000 1999 ----------------------------------------------- -------------- ------------ Operating revenues $1,374.0 $1,343.8 $1,226.0 Less: Fuel used in generation (223.9) (231.6) (214.4) Purchased power (233.9) (182.7) (141.5) ----------------------------------------------- -------------- ------------ Margin $916.2 $929.5 $870.1 =============================================== ============== ============ o 2001 vs 2000 Sales margin decreased primarily due to milder weather and the impact of the slowing economy, which was partially offset by customer growth and lower fuel costs. o 2000 vs 1999 Sales margin increased primarily due to more favorable weather and 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 in 2000, were as follows: Classification 2001 % Change 2000 % Change --------------------------------------------------------------------- -------- Residential (170,509) (2.5%) 396,179 6.3% Commercial (17,194) - 353,621 5.9% Industrial (317,659) (4.7%) 524,969 8.5% Sales for resale (excluding interchange) (108,236) (8.8%) 33,505 2.8% Other (18,927) (3.4%) 34,676 6.7% --------------------------------------------- ------------ Total territorial (632,525) (3.0%) 1,342,950 6.7% Negotiated Market Sales Tariff 207,984 10.0% 264,257 15.7% --------------------------------------------- ------------ Total (424,541) (2.0%) 1,607,207 7.4% ===================================================================== ======== o 2001 vs 2000 Sales volume decreased primarily due to milder weather and the impact of the slowing economy. o 2000 vs 1999 Sales volume increased primarily due to more favorable weather and customer growth. In March 2001 Summer Station returned to service after having been taken out of service on October 7, 2000 for a planned maintenance and refueling outage. During initial inspection activities, plant personnel discovered a small leak in a weld in a primary coolant system pipe. Repairs were completed and the integrity of the new welds was verified through extensive testing. The NRC was closely involved throughout this process and approved SCE&G's actions, as well as the restart schedule. Also in April 2001 SCE&G's 385 megawatt coal-fired Cope Generating Station returned to service after having been taken out of service in January 2001 due to an electrical ground in the generator. The SCPSC has approved recovery of the cost of replacement power related to both of these outages through SCE&G's fuel adjustment clause. Gas Distribution Gas Distribution is comprised of the local distribution operations of SCE&G. Gas distribution sales margins for 2001, 2000 and 1999, excluding the cumulative effect of accounting change in 2000, were as follows: Millions of dollars 2001 2000 1999 ----------------------------------------------------------------------- Operating revenues $341.0 $325.1 $239.0 Less: Gas purchased for resale (251.6) (233.8) (152.6) ----------------------------------------------------------------------- Margin $89.4 $91.3 $86.4 ======================================================================= o 2001 vs 2000 Sales margin decreased primarily as a result of the slowing economy and increased competition with alternate fuels. o 2000 vs 1999 Sales margin increased primarily as a result of more favorable weather. 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 in 2000, were as follows: Classification 2001 % Change 2000 % Change ---------------------------------- ------------- -------------- ------------- Residential (3,249,400) (22.4%) 2,682,707 22.7% Commercial (1,511,368) (11.8%) 1,118,193 9.6% Industrial (2,828,121) (16.5%) (828,737) (4.6)% Transportation gas 375,436 18.0% 110,220 5.6% --- ------- ---- ------- ------------------- Total (7,213,453) (15.5%) 3,082,383 7.1% ================================== ============= ============== ============= o 2001 vs 2000 Sales volume decreased due to the slowing economy and use of alternate fuels by industrial customers. o 2000 vs 1999 Sales volume increased due to colder weather and customer growth, which were partially offset by curtailments and use of alternate fuels by industrial customers. Other Operating Expenses Increases (decreases) in other operating expenses were as follows: Millions of dollars 2001 % Change 2000 % Change ------------------------------------------------------------------------------- Other operation and maintenance $7.0 2.3% $(7.3) (2.3%) Depreciation and amortization 5.1 3.2% 4.8 3.1% Other taxes 1.5 1.5% 3.5 3.7% ----------------------------------------- ------------- Total $13.6 2.4% $1.0 0.2% =============================================================================== o 2001 vs 2000 Other operation and maintenance expenses increased primarily as a result of increases in employee benefit costs. Depreciation and amortization increased primarily as a result of normal increases in utility plant. Other taxes increased primarily due to increased property taxes. o 2000 vs 1999 Other 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. Interest Expense Increases (decreases) in interest expense, excluding the debt component of AFC, were as follows: Millions of dollars 2001 % Change 2000 % Change -------------------------------------------------------------------------------- Interest on long-term debt, net $12.0 11.9% $4.0 4.1% Other interest expense (2.4) (29.6%) (0.5) (5.8%) --------------------------------------------- ----------- Total $9.6 8.8% $3.5 3.3% ================================================================================ Interest expense in 2001 increased as a result of increased borrowings. Interest expense in 2000 increased as a result of increased borrowings and increased weighted average interest rates on short-term and long-term borrowings. Income Taxes Income taxes decreased approximately $9.8 million for the year 2001 compared to 2000 and increased approximately $23.4 million for the year ended 2000 compared to 1999. 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, 2001 Expected Maturity Date Millions of dollars Liabilities 2002 2003 2004 2005 2006 Thereafter Total Fair Value ---------------------------- ------------ ----------- ----------- ----------- ------------ ------------- ------------ ------------ Long-Term Debt: Fixed Rate ($) 27.6 129.7 123.9 173.9 154.7 1,561.0 1,542.9 951.2 Average Interest Rate 6.73% 6.37% 7.52% 7.40% 8.66% 7.33% 7.33% December 31, 2000 Expected Maturity Date Millions of dollars Liabilities 2001 2002 2003 2004 2005 Thereafter Total Fair Value ---------------------------- ------------ ----------- ----------- ----------- ------------ ------------- ------------ ------------ Long-Term Debt: Fixed Rate ($) 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% 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............................................... 94 Consolidated Financial Statements: Consolidated Balance Sheets as of December 31, 2001 and 2000................ 95 Consolidated Statements of Income for years ended December 31, 2001, 2000 and 1999............................................................ 97 Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999..................................................... 98 Consolidated Statements of Capitalization as of December 31, 2001 and 2000.................................................................99 Consolidated Statements of Common Equity for the years ended December 31, 2001, 2000 and 1999.................................................... 101 Notes to Consolidated Financial Statements................................ 102 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, 2001 and 2000 and the related Consolidated Statements of Income, Common Equity and of Cash Flows for each of the three years in the period ended December 31, 2001. 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, 2001 and 2000 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 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 8, 2002

SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED BALANCE SHEETS ------------------------------------------------------------------------------------- ---------------- ------------------- December 31, (Millions of dollars) 2001 2000 ------------------------------------------------------------------------------------- ---------------- ------------------- Assets Utility Plant (Notes 1 & 5): Electric $4,563 $4,453 Gas 425 409 Other 188 186 ------------------------------------------------------------------------------------- ---------------- ------------------- Total 5,176 5,048 Less accumulated depreciation and amortization 1,841 1,720 ------------------------------------------------------------------------------------- ---------------- ------------------- Total 3,335 3,328 Construction work in progress 511 230 Nuclear fuel, net of accumulated amortization 45 57 ------------------------------------------------------------------------------------- ---------------- ------------------- Utility Plant, Net 3,891 3,615 ------------------------------------------------------------------------------------- ---------------- ------------------- Nonutility Property and Investments, Net 24 21 ------------------------------------------------------------------------------------- ---------------- ------------------- Current Assets: Cash and temporary investments (Notes 1 &11) 78 60 Receivables 212 284 Receivables - affiliated companies 4 3 Inventories (At average cost) (Note 6): Fuel 39 21 Materials and supplies 48 46 Emission allowances 13 20 Prepayments 6 5 ------------------------------------------------------------------------------------- ---------------- ------------------- Total Current Assets 400 439 ------------------------------------------------------------------------------------- ---------------- ------------------- Deferred Debits: Environmental 24 20 Nuclear plant decommissioning fund (Note 1) 79 72 Pension asset, net (Note 4) 239 196 Due from affiliates - postretirement benefits (Note 4) 15 13 Other regulatory assets (Note 1) 193 191 Other 97 104 ------------------------------------------------------------------------------------- ---------------- ------------------- Total Deferred Debits 647 596 ------------------------------------------------------------------------------------- ---------------- ------------------- Total $4,962 $4,671 ===================================================================================== ================ ===================

SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED BALANCE SHEETS ------------------------------------------------------------------------- -------------------- -------------------- December 31, (Millions of dollars) 2001 2000 ------------------------------------------------------------------------- -------------------- -------------------- Capitalization and Liabilities Shareholders' Investment: Common equity (Note 8) $1,750 $1,657 Preferred stock (Not subject to purchase or sinking funds) (Note 9) 106 106 ------------------------------------------------------------------------- -------------------- -------------------- Total Shareholders' Investment 1,856 1,763 Preferred Stock, net (Subject to purchase or sinking funds) (Note 9) 10 10 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 (Note 9) 50 50 Long-Term Debt, net (Notes 5 & 11) 1,412 1,267 ------------------------------------------------------------------------- -------------------- -------------------- Total Capitalization 3,328 3,090 ------------------------------------------------------------------------- -------------------- -------------------- Current Liabilities: Short-term borrowings (Notes 6, 7 & 11) 165 188 Current portion of long-term debt (Note 5) 28 28 Accounts payable 99 103 Accounts payable - affiliated companies (Note 1) 78 58 Customer prepayment and deposits 19 17 Taxes accrued 80 51 Interest accrued 27 22 Dividends declared 42 44 Deferred income taxes, net (Notes 1 & 10) 12 20 Other 8 10 ------------------------------------------------------------------------- -------------------- -------------------- Total Current Liabilities 558 541 ------------------------------------------------------------------------- -------------------- -------------------- Deferred Credits: Deferred income taxes, net (Notes 1 & 10) 599 584 Deferred investment tax credits (Notes 1 & 10) 109 109 Reserve for nuclear plant decommissioning (Note 1) 79 72 Due to affiliates - pension asset (Note 4) 16 14 Postretirement benefits (Note 4) 122 113 Regulatory liabilities 81 65 Other 70 83 ------------------------------------------------------------------------- -------------------- -------------------- Total Deferred Credits 1,076 1,040 ------------------------------------------------------------------------- -------------------- -------------------- Commitments and Contingencies (Note 12) - - ------------------------------------------------------------------------- -------------------- -------------------- Total $4,962 $4,671 ========================================================================= ==================== ====================

See Notes to Consolidated Financial Statements. SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME

-------------------------------------------------------------------------- ------------------- --------------- ---------------- - For the Years Ended December 31, 2001 2000 1999 -------------------------------------------------------------------------- ------------------- --------------- ---------------- - (Millions of Dollars, except per share amounts) Operating Revenues (Notes 1, 2 & 3): Electric $1,374 $1,344 $1,226 Gas 341 325 239 -------------------------------------------------------------------------- ------------------- --------------- ---------------- - Total Operating Revenues 1,715 1,669 1,465 -------------------------------------------------------------------------- ------------------- --------------- ---------------- - Operating Expenses: Fuel used in electric generation 224 232 214 Purchased power (including affiliated purchases) 234 183 142 Gas purchased for resale 252 234 153 Other operation and maintenance 315 308 316 Depreciation and amortization (Note 1) 163 158 153 Other taxes 99 97 94 -------------------------------------------------------------------------- ------------------- --------------- ---------------- - Total Operating Expenses 1,287 1,212 1,072 -------------------------------------------------------------------------- ------------------- --------------- ---------------- - Operating Income 428 457 393 -------------------------------------------------------------------------- ------------------- --------------- ---------------- - Other Income: Other Income, including allowance for equity funds used during construction (Note 1) 26 14 9 Gain on sale of assets 4 2 3 -------------------------------------------------------------------------- ------------------- --------------- ---------------- - Total Other Income 30 16 12 -------------------------------------------------------------------------- ------------------- --------------- ---------------- - Income Before Interest Charges, Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change 458 473 405 Interest Charges, Net of Allowance for Borrowed Funds Used During Construction (Note 1) 109 105 102 -------------------------------------------------------------------------- ------------------- --------------- ---------------- - Income Before Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change 349 368 303 Income Taxes (Note 10) 123 133 110 -------------------------------------------------------------------------- ------------------- --------------- ---------------- - Income Before Preferred Stock Dividends and Cumulative Effect of Accounting Change 226 235 193 Preferred Dividend Requirement of Company - Obligated Mandatorily Redeemable Preferred Securities 4 4 4 -------------------------------------------------------------------------- ------------------- --------------- ---------------- - Income Before Cumulative Effect of Accounting Change 222 231 189 Cumulative Effect of Accounting Change, net of taxes (Note 2) - 22 - -------------------------------------------------------------------------- ------------------- --------------- ---------------- - Net Income 222 253 189 Preferred Stock Cash Dividends (At stated rates) 7 7 7 -------------------------------------------------------------------------- ------------------- --------------- ---------------- - Earnings Available for Common Shareholder $215 $246 $182 ========================================================================== =================== =============== ================ =

See Notes to Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, (Millions of dollars) 2001 2000 1999 ----------------------------------------------------------------------- ------------ ------------- ------------- Cash Flows From Operating Activities: Net income $222 $253 $189 Adjustments to reconcile net income to net cash provided from operating activities: Cumulative effect of accounting change, net of taxes - (22) - Depreciation and amortization 165 159 154 Amortization of nuclear fuel 16 16 18 Gain on sale of assets (4) (2) (3) Allowance for funds used during construction (22) (6) (6) Under collection, fuel adjustment clause (3) (34) (6) Changes in certain assets and liabilities: (Increase) decrease in receivables 71 (56) (17) (Increase) decrease inventories (13) 8 (16) (Increase) decrease in pension asset (43) (43) (29) (Increase) decrease in other regulatory assets 1 15 16 Increase (decrease) in deferred income taxes, net 27 60 16 Increase (decrease) in other regulatory liabilities 22 6 (6) Increase (decrease) in postretirement benefits 9 15 11 Increase (decrease) in accounts payable 16 50 (9) Increase (decrease) in taxes accrued 29 (23) (15) Other, net (32) (17) 13 ----------------------------------------------------------------------- ------------ ------------- ------------- Net Cash Provided From Operating Activities 461 379 310 ----------------------------------------------------------------------- ------------ ------------- ------------- Cash Flows From Investing Activities: Utility property additions and construction expenditures, net of AFC (427) (277) (227) Increase in nonutility property (2) (1) - Proceeds on sales of assets 3 2 3 Increase in investments (7) (1) (6) ----------------------------------------------------------------------- ------------ ------------- ------------- Net Cash Used For Investing Activities (433) (277) (230) ----------------------------------------------------------------------- ------------ ------------- ------------- Cash Flows From Financing Activities: Proceeds: Issuance of First Mortgage Bonds 149 148 99 Capital contribution from parent 33 - - Repayment and repurchases: Mortgage bonds - (100) (10) Notes and loans - - - Other long-term debt (5) (4) (9) Preferred stock - (1) - Dividend payments: Common Stock (157) (131) (133) Preferred stock (7) (7) (7) Short-term borrowings, net (23) (25) 22 ----------------------------------------------------------------------- ------------ ------------- ------------- Net Cash Used For Financing Activities (10) (120) (38) ----------------------------------------------------------------------- ------------ ------------- ------------- Net Increase (Decrease) in Cash and Temporary Investments 18 (18) 42 Cash and Temporary Investments, January 1 60 78 36 ----------------------------------------------------------------------- ------------ ------------- ------------- Cash and Temporary Investments, December 31 $78 $60 $78 ======================================================================= ============ ============= ============= Supplemental Cash Flow Information: Cash paid for - Interest (net of capitalized interest of $9, $4 $131 $102 $99 and $3) - Income taxes 70 97 94

See Notes to Consolidated Financial Statements. SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION

---------------------------------------------------------------------------------------- ------------- ------- ------------ ------- December 31, (Millions of dollars) 2001 2000 ---------------------------------------------------------------------------------------- ------------- ------- ------------ ------- Common Equity (Note 8): Common stock, $4.50 par value, authorized 50,000,000 shares; issued and outstanding 40,296,147 shares in 2001 and 2000 $181 $181 Premium on common stock 395 395 Other paid-in capital 470 437 Capital stock expense (5) (5) Retained earnings 709 649 ---------------------------------------------------------------------------------------- ------------- ------- ------------ ------- Total Common Equity 1,750 53 % 1,657 54% ---------------------------------------------------------------------------------------- ------------- ------- ------------ ------- 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 Redemption Price Outstanding Series 2001 2000 ------ ---- ---- $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 3% ---------------------------------------------------------------------------------------- ------------- ------- ------------ ------- 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 2001 2000 Redemption Price ------ ---- ---- ---------------- 4.50% 8,397 9,600 51.00 1 1 4.60% (A) 14,052 16,052 51.00 1 1 4.60% (B) 54,400 57,800 50.50 3 3 5.125% 66,000 67,000 51.00 3 3 6.00% 66,635 69,835 50.50 3 3 ------------- ----------- Total 209,484 220,287 ============= =========== $25 Par Value - Authorized 2,000,000 shares; None outstanding in 2000 and 1999 ----------------------------------------------------------------------------------------- ------------ -------- ----------- -------- Total Preferred Stock (Subject to purchase or sinking funds) 11 11 Less: Current portion, including sinking funds requirements (1) (1) ----------------------------------------------------------------------------------------- ------------ -------- ----------- -------- Total Preferred Stock, Net (Subject to purchase or sinking funds) (Notes 9 & 11) 10 - % 10 -% ----------------------------------------------------------------------------------------- ------------ -------- ----------- -------- 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 the Company, due 2027 (Note 9) 50 2% 50 2% ----------------------------------------------------------------------------------------- ------------ -------- ----------- --------

------------------------------------------------------------- ----------- -------------- -------- -------------- ----------- December 31, (Millions of dollars) 2001 2000 ------------------------------------------------------------- ----------- -------------- -------- -------------- ----------- Long-Term Debt (Notes 5 & 11) First Mortgage Bonds: Series Year of Maturity 6 1/4% 2003 $100 $100 7.70% 2004 100 100 7 1/2% 2005 150 150 6 1/8% 2009 100 100 6.70% 2011 150 - 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 16 17 Charleston Franchise Agreement, due 1997-2002 4 7 Other 2 3 ------------------------------------------------------------- ----------- -------------- -------- -------------- ----------- Total Long-Term Debt 1,443 1,298 Less - Current maturities, including sinking fund (28) (28) requirements - Unamortized discount (3) (3) ------------------------------------------------------------- ----------- -------------- -------- -------------- ----------- Total Long-Term Debt, Net 1,412 42% 1,267 41% ------------------------------------------------------------- ----------- -------------- -------- -------------- ----------- Total Capitalization $3,328 100% $3,090 100% ============================================================= =========== ============== ======== ============== ===========

See Notes to Consolidated Financial Statements. SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED STATEMENTS OF COMMON EQUITY

Premium Other Capital Total Millions of dollars Common Stock On Common Paid in Stock Retained Common Shares Amount Stock Capital Expense Earnings Equity ------------------------------------------ ------------ ---------- --------------- ------------ ---------- ----------- ----------- Balance at December 31, 1998 40,296,147 $181 $395 $437 $(5) $491 $1,499 ------------------------------------------ ------------ ---------- --------------- ------------ ---------- ----------- ----------- Net Income 182 182 Cash Dividends Declared (123) (123) ------------------------------------------ ------------ ---------- --------------- ------------ ---------- ----------- ----------- Balance at December 31, 1999 40,296,147 181 395 437 (5) 550 1,558 ------------------------------------------ ------------ ---------- --------------- ------------ ---------- ----------- ----------- Net Income 246 246 Cash Dividends Declared (147) (147) ------------------------------------------ ------------ ---------- --------------- ------------ ---------- ----------- ----------- Balance at December 31, 2000 40,296,147 181 395 437 (5) 649 1,657 ------------------------------------------ ------------ ---------- --------------- ------------ ---------- ----------- ----------- Capital Contributions From Parent 33 - 33 Net Income 215 215 Cash Dividends Declared (155) (155) ------------------------------------------ ------------ ---------- --------------- ------------ ---------- ----------- ----------- ------------------------------------------ ------------ ---------- --------------- ------------ ---------- ----------- Balance at December 31, 2001 40,296,147 $181 $395 $470 $(5) $709 $1,750 ========================================== ============ ========== =============== ============ ========== =========== ===========

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, as amended (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 South Carolina Pipeline Corporation (SCPC), and at December 31, 2001 and 2000, the Company had approximately $23.0 million and $45.9 million, respectively, payable to SCPC for such gas purchases. The Company purchases all of the electric generation of Williams Station, which is owned by South Carolina Generating Company (GENCO), under a unit power sales agreement. At December 31, 2001 and 2000 the Company had approximately $9.5 million and $8.3 million, respectively, payable to GENCO for unit power purchases. Such unit power purchases, which are included in "Purchased power," amounted to approximately $95.8 million, $100.2 million and $105.5 million in 2001, 2000 and 1999, respectively. Total interest income, based on market interest rates, associated with the Company's advances to affiliated companies was approximately $0.7 million, $1.1 million and $0.9 million in 2001, 2000 and 1999, 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, 2001, approximately $217 million and $81 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities of approximately $125 million and $71 million, respectively. The electric and gas regulatory assets of approximately $52 million and $40 million, respectively (excluding deferred income tax assets), are recoverable through rates. The Public Service Commission of South Carolina (SCPSC) has reviewed and approved most of the items shown as regulatory assets through specific orders. Other items represent costs which were not yet approved for recovery by the SCPSC, but are the subject of current or future filings. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in current rate orders received by the Company. However, ultimate recovery is subject to SCPSC approval. 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 SCPSC. 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 $963.0 million and $965.0 million as of December 31, 2001 and 2000, respectively. Accumulated depreciation associated with the Company's share of Summer Station was approximately $407.4 million and $387.7 million as of December 31, 2001 and 2000, respectively. The Company's share of the direct expenses associated with operating Summer Station is included in "Other operation and maintenance" expenses. As allowed by the SCPSC, the Company accrues in advance its portion of estimated scheduled outage costs for Summer Station. Total outage costs for the planned outage in April 2002 are estimated to be approximately $13 million, of which the Company will be responsible for approximately $8.9 million. As of December 31, 2001, the Company had accrued $5.9 million. 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 8.8%, 8.1% and 7.7% for 2001, 2000 and 1999, 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). Unbilled revenues totaled approximately $39.5 million and $44.9 million as of December 31, 2001 and 2000, respectively. 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 SCPSC 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 $47.4 million and $35.5 million at December 31, 2001 and 2000, 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 SCPSC 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, 2001 and 2000 the Company had undercollected through the gas cost recovery procedure approximately $12.2 million and $12.7 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%, 2.98% and 2.99% for 2001, 2000 and 1999, 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 one-third 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 2001, 2000 and 1999) 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 $2.4 million at December 31, 2001, 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. Also under provisions of the income tax allocation agreement, tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including SCE&G, in the form of capital contributions. In 2001, capital contributions of approximately $33 million were received by SCE&G under such provisions. 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 evaluate 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. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.4 million and $20.2 million at December 31, 2001 and 2000, 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. New Accounting Standards SFAS 143, "Accounting for Asset Retirement Obligations," provides guidance for recording and disclosing a liability related to the future obligation to retire an asset (such as a nuclear plant). The Company will adopt SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on the Company's results of operations, cash flows or financial position has not been determined but could be material. The provisions of SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" are effective January 1, 2002. This Statement requires that one accounting model be used for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired, and broadens the presentation of discontinued operations to include more disposal transactions. There was no impact on the Company's financial statements from the initial adoption of SFAS 144. O. Reclassifications Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2001. 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 for the year ended December 31, 1999, compared to $189 million, as reported. 3. RATE AND OTHER REGULATORY MATTERS Electric On April 24, 2001 the SCPSC approved the Company's request to increase the fuel component of rates charged to electric customers from 1.330 cents per kilowatt-hour to 1.579 cents per kilowatt-hour. The increase reflects higher fuel costs projected for the period May 2001 through April 2002. The increase also provides recovery over a two-year period of under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of the Company's base load generating plants in winter 2000-2001. The new rates were effective as of the first billing cycle in May 2001. On September 14, 1999 the SCPSC 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 SCPSC 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 SCPSC. 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, 2001 no accelerated depreciation has been recorded. The accelerated capital recovery plan will be accomplished through existing customer rates. On January 9, 1996 the SCPSC authorized a return on common equity of 12.0 percent. The SCPSC 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 SCPSC approved accelerated amortization 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, which enabled the Company to recover the balances as of the end of the year 2000. Gas The Company's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by the Company. The Company's cost of gas component in effect during the years ended December 31, 2001 and 2000 was as follows: Rate Per Therm Effective Date Rate Per Therm Effective Date $.993 January-February 2001 $.543 January-July 2000 $.793 March-October 2001 $.688 August-October 2000 $.596 November-December 2001 $.782 November-December 2000 On July 5, 2000 the SCPSC 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. The retroactive effect was recorded in the second quarter of 2000. In 1994 the SCPSC 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 October 2001, as a result of the annual review, the SCPSC approved the Company's request to increase the billing surcharge from 1.1cents per therm to 3.0 cents per therm, which is intended to provide for the recovery of the balance remaining at December 31, 2001 of $24.4 million prior to the end of the year 2005. Transit In September 1992 the SCPSC 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 SCPSC also required $.40 fares for low income customers and denied SCE&G's request for certain bus route and schedule changes. The new rates were placed into effect in October 1992. After several appeals and petitions for reconsideration to the South Carolina Circuit Court (Circuit Court) and the South Carolina Supreme Court (Supreme Court) by the various parties, on September 27, 2000 the SCPSC issued an order granting certain relief requested by the Company. On September 29, 2000 the Consumer Advocate of South Carolina (Consumer Advocate) filed a motion with the SCPSC for a stay of this order. On October 3, 2000 the SCPSC 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 SCPSC's order granting relief. The Circuit Court has held in abeyance any appellate review pending the outcome of current negotiations on the transfer of the transit system from the Company to an unaffiliated regional authority.. 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. 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. In connection with the joint ownership arrangements surrounding Summer Station, as of December 31, 2001 the Company has recorded within deferred credits an $8.4 million obligation to Santee Cooper, representing an estimate of the net pension asset attributable to the Company's contributions to the plan that were recovered through billings to Santee Cooper for its one-third portion of shared costs. The Company has also recorded a $6.0 million receivable from Santee Cooper representing an estimate of its portion of the unfunded net postretirement benefit obligation. As allowed by SFAS 87, the Company records net periodic benefit cost (income) utilizing beginning of the year assumptions. 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 2001 2000 1999 2001 2000 1999 ---- ---- ---- ---- ---- ---- Service Cost $7.9 $8.3 $10.0 $3.0 $2.7 $3.0 Interest Cost 38.5 33.5 27.9 12.1 10.2 9.5 Expected return on assets (83.5) (76.6) (65.5) n/a n/a n/a Prior service cost amortization 5.8 3.0 1.1 0.9 0.8 0.7 Actuarial (gain) loss (12.8) (12.2) (8.6) 0.7 - 1.2 Transition amount amortization 0.8 0.8 0.8 0.8 0.8 1.7 Special termination benefit cost - 5.5 - - 1.0 - Amount attributable to Company affiliates 2.2 1.7 1.1 (3.1) ---- --- ----- --- ----- --- ----- ----- --- (1.6) (0.9) Net periodic benefit (income) cost $(41.1) $(41.5) $(27.7) $14.4 $12.9 $16.2 ====== ====== ====== = ===== ===== ===== Assumptions Retirement Benefits Other Postretirement Benefits -------------------------------------- -------------------------------------- As of December 31 2001 2000 1999 2001 2000 1999 ---- ---- ---- ---- ---- ---- Discount rate 7.5% 8.0% 8.0% 7.5% 8.0% 8.0% 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 2001 2000 2001 2000 ---- ---- ---- ---- Benefit obligation, January 1 $479.3 $362.3 $139.0 $129.8 Service cost 7.9 8.3 3.0 2.7 Interest cost 38.5 33.5 12.1 10.2 Plan participants' contributions - 0.1 0.5 0.5 Plan amendment 21.5 65.4 1.2 0.9 Actuarial (gain) loss 19.6 1.6 20.1 (7.8) Acquisition/merger of plans - 39.8 - 11.2 Benefits paid (36.0) (31.7) (9.2) (8.5) -- ----- -- ----- ------ ---- ---- ---- Benefit obligation, December 31 $530.8 $479.3 $166.7 $139.0 ====== ====== ====== ======

Change in Plan Assets Retirement Benefits ---------------------------------------------- Millions of dollars 2001 2000 ---- ---- Fair value of plan, assets, January 1 $894.3 $783.0 Actual return on plan assets (26.7) 96.7 Company contribution - - Plan participants' contributions - 0.1 Acquisition/merger of plans - 46.2 Benefits paid (36.0) (31.7) ----- -- ----- Fair value of plan assets, December 31 $831.6 $894.3 ====== ====== Funded Status of Plans Retirement Benefits Other Postretirement Benefits --------------------------------- Millions of dollars 2001 2000 2001 2000 ----------- --------------------------- ----------------- Funded status, December 31 $300.8 $415.0 $(166.7) $(139.0) Unrecognized actuarial (gain) loss (155.0) (297.6) 32.5 13.0 Unrecognized prior service cost 89.4 73.7 4.8 4.5 Unrecognized net transition obligation 4.0 4.8 7.4 8.3 -------- ----- --- ------- ---- ------ --- Net amount recognized in Consolidated Balance Sheet $239.2 $195.9 $(122.0) $(113.2) ====== ========= ======== ========

Health Care Trends The determination of net periodic other postretirement benefit cost is based on the following assumptions: 2001 2000 1999 ----------------------------------------------- ---------- ---------- Health care cost trend rate 8.5% 7.5% 8.0% Ultimate health care cost trend rate 5.0% 5.5% 5.5% Year achieved 2009 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: 1% 1% Millions of dollars Increase Decrease --------------- ---------------- Effect on health care cost $0.1 $(0.1) Effect on postretirement obligation 1.6 (1.8) 5. LONG-TERM DEBT The annual amounts of long-term debt maturities and sinking fund requirements for the years 2002 through 2006 are summarized as follows: ---------------- ----------------- ------------------ ----------------- Year Amount Year Amount ---------------- ----------------- ------------------ ----------------- (Millions of dollars) 2002 $27.6 2005 $173.9 2003 123.7 2006 154.7 2004 123.9 ---------------- ----------------- ------------------ ----------------- Approximately $23.5 million of the portion of long-term debt payable in 2002 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. 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 Company's commercial paper outstanding totaled $114.7 million and $117.5 million at December 31, 2001 and 2000, at weighted average interest rates of 1.95 percent and 6.59 percent, respectively. Substantially all utility plant is pledged as collateral in connection with long-term debt. On January 31, 2002 the Company issued $300 million of first mortgage bonds having an annual interest rate of 6.625 percent and maturing February 1, 2032. The proceeds from the sale of these bonds were used to reduce short-term debt primarily incurred as a result of the Company's construction program and to redeem its First and Refunding Mortgage Bonds, 8 7/8 percent Series due August 15, 2021. 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 17, 2002. 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. Fuel Company commercial paper outstanding totaled $50.1 million and $70.2 million at December 31, 2001 and 2000, respectively, at weighted average interest rates of 2.06 percent and 6.59 percent, respectively. 7. SHORT-TERM BORROWINGS Details of lines of credit (including uncommitted lines of credit) and short-term borrowings at December 31, 2001 and 2000, are as follows: Millions of dollars 2001 2000 -------------------------------------------------------- --------------- Authorized lines of credit $300.0 $300.0 Unused lines of credit $300.0 $300.0 Short-term borrowings outstanding Commercial paper (270 days or less) $164.8 $187.7 Weighted average interest rate 1.97% 6.59% The Company pays fees to banks as compensation for its committed lines of credit. 8. RETAINED EARNINGS The Company's Restated Articles of Incorporation 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, 2001 approximately $37 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 2002 through 2006 is $2.8 million. The changes in "Total Preferred Stock (Subject to purchase or sinking funds)" during 2001, 2000 and 1999 are summarized as follows: Number of Shares Millions of Dollars -------------------------------------------------------- ----------------------- 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 Shares Redeemed - $50 par value (10,803) (0.5) -------------------------------------------------------- ----------------------- Balance at December 31, 2001 209,484 $10.5 ======================================================== ======================= 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 2001, 2000 and 1999 is as follows: Millions of dollars 2001 2000 1999 --------------------------------------------------------------- ----------------- ----------------- Current taxes: Federal $83.8 $78.4 $91.3 State 10.2 7.8 0.3 --------------------------------------------------------------- ----------------- ----------------- --------------------------------------------------------------- ----------------- ----------------- Total current taxes 94.0 86.2 91.6 --------------------------------------------------------------- ----------------- ----------------- --------------------------------------------------------------- ----------------- ----------------- Deferred taxes, net: Federal 8.7 31.8 7.7 State 1.6 5.2 1.4 --------------------------------------------------------------- ----------------- ----------------- --------------------------------------------------------------- ----------------- ----------------- Total deferred taxes 10.3 37.0 9.1 --------------------------------------------------------------- ----------------- ----------------- --------------------------------------------------------------- ----------------- ----------------- Investment tax credits: Deferred - State 5.0 5.0 13.4 Amortization of amounts deferred - State (1.5) (1.3) (1.2) Amortization of amounts deferred - Federal (3.2) (3.2) (3.2) --------------------------------------------------------------- ----------------- ----------------- Total investment tax credits 0.3 0.5 9.0 --------------------------------------------------------------- ----------------- ----------------- Non-conventional fuel tax credits: Deferred - Federal 18.7 9.4 n/a --------------------------------------------------------------- ----------------- ----------------- Total income tax expense $123.3 $133.1 $109.7 =============================================================== ================= =================

The difference between actual income tax expense and the amount calculated from the application of the statutory 35 percent Federal income tax rate to pre-tax income before cumulative effect of accounting change is reconciled as follows: Millions of dollars 2001 1999 2000 ---------------------------------------------------------------- ----------------- ----------------- ----------------- Income before cumulative effect of accounting change $214.5 $223.9 $181.8 Total income tax expense: Charged to operating expense 112.8 123.8 103.1 Charged to other items 10.5 9.3 6.6 Preferred stock dividends 11.2 11.2 11.2 ---------------------------------------------------------------- ----------------- ----------------- ----------------- Total pre-tax income $349.0 $368.2 $302.7 ================================================================ ================= ================= ================= ================================================================ ================= ================= ================= Income taxes on above at statutory Federal income tax rate $122.2 $128.9 $106.0 Increases (decreases) attributed to: State income taxes (less Federal income tax effect) 9.9 10.9 9.0 Amortization of Federal investment tax credits (3.2) (3.2) (3.2) Other differences, net (5.6) (3.5) (2.1) ---------------------------------------------------------------- ----------------- ----------------- ----------------- ---------------------------------------------------------------- ----------------- ----------------- ----------------- Total income tax expense $123.3 $133.1 $109.7 ================================================================ ================= ================= =================

The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $611.3 million at December 31, 2001 and $604.1 million at December 31, 2000 (see Note 1I), are as follows: Millions of dollars 2001 2000 ------------------------------------------------------- ------------------ Deferred tax assets: Nondeductible reserves $54.5 $49.0 Unamortized investment tax credits 56.7 57.3 Deferred compensation 22.9 23.2 Cycle billing 10.6 - Other 6.2 - ------------------------------------------------------- ------------------ Total deferred tax assets 150.9 129.5 ------------------------------------------------------- ------------------ Deferred tax liabilities: Property, plant and equipment 647.6 636.3 Pension plan benefit income 81.1 65.3 Deferred fuel costs 22.8 18.5 Cycle billing - 1.9 Other 10.7 11.6 ------------------------------------------------------- ------------------ Total deferred tax liabilities 762.2 733.6 ------------------------------------------------------- ------------------ Net deferred tax liability $611.3 $604.1 ======================================================= ================== 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, 1999 and 2000. 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, 2001 and 2000 are as follows: Millions of dollars 2001 2000 ----------------------------------------------------------- -------------------- Estimated Estimated Carrying Fair Carrying Fair Amount Value Amount Value ---------------------------------------------------------------------- --------- Assets: Cash and temporary cash investments $77.9 $77.9 $60.2 $60.2 Investments 6.5 6.5 6.4 6.4 Liabilities: Short-term borrowings 164.8 164.8 187.7 187.7 Long-term debt 1,440.0 1,542.9 1,294.1 1,331.6 Preferred stock (subject to purchase or sinking funds) 10.4 8.5 11.0 8.7 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 is considered to approximate carrying value. 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. Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. The Company's adoption did not have a material impact on the Company's results of operations, cash flows or financial position. 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. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost $250 million and be completed in 2005. Any costs incurred by the Company are expected to be recoverable through electric rates. 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 costs, permit assessments under certain conditions to cover insurer's losses. Based on the current annual premium, the Company's portion of the retrospective premium assessment would not exceed $14.1 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 would have a material adverse impact on the Company's results of operations, cash flows and financial position. C. Environmental In September 1992 the EPA notified the Company, among others, of its 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 various industrial operations, including one of the Company's decommissioned MGPs. Field work at the site began in November 1993 and has required the submission of several investigative reports and the implementation of several work plans. In September 2000, the Company was notified by the South Carolina Department of Health and Environmental Control (DHEC) that benzene contamination was detected in the intermediate aquifer on surrounding properties of the Calhoun Park area site. The EPA required that the Company conduct a focused Remedial Investigation/Feasibility Study on the intermediate aquifer, which was completed in June 2001. The EPA expects to issue a Record of Decision dealing with the intermediate aquifer and sediments in June 2002. The Company anticipates that major remediation activities will be completed in 2003, with certain monitoring activities continuing until 2007. As of December 31, 2001, the Company has spent approximately $15.8 million to remediate the Calhoun Park area site. Total remediation costs are estimated to be $21.9 million. The Company owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by DHEC. The Company is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. The Company anticipates that major remediation activities for these three sites will be completed between 2003-2005. The Company has spent approximately $2.0 million related to these sites, and expects to incur an additional $6.0 million. D. Franchise Agreement See Note 5 for a discussion of the electric franchise agreement between the Company and the City of Charleston. E. Claims and Litigation The Company is engaged in various claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company. F. Operating Lease Commitments The Company is obligated under various operating leases with respect to office space, furniture and equipment. Leases expire at various dates through 2009. Rent expense totaled approximately $9.0 million, $5.9 million and $4.5 million in 2001, 2000 and 1999, respectively. Future minimum rental payments under such leases are as follows: Millions of dollars 2002 $12.0 2003 11.5 2004 9.9 2005 9.4 2006 9.2 Thereafter 25.8 ------ $77.8 G. Purchase Commitments Purchase commitments for coal supply and other contracts are as follows: 2002 $166.7 2003 142.6 2004 60.4 2005 0.2 2006 0.2 Thereafter 10.6 ------- $380.7 13. SEGMENT OF BUSINESS INFORMATION The Company's reportable segments 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 SCPSC and by 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 33 counties in South Carolina covering approximately 22,000 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 2001 Operations Distribution Other Eliminations Total ---------------------------------- ------------- ------------- ----------------- ---------------- ------------------ External Customer Revenue $1,374 $341 - - $1,715 Intersegment Revenue 212 - - $(212) - Operating Income (Loss) 405 26 - (3) 428 Interest Expense 3 n/a $4 106 109 Depreciation & Amortization 151 12 - - 163 Segment Assets 5,034 428 - (500) 4,962 Expenditures for Assets 409 16 - 4 429 Deferred Tax Assets - n/a - - - ---------------------------------- ------------- ------------- ----------------- ---------------- ------------------ 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 Segment Assets 4,655 416 - (400) 4,671 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 2 - (205) 203 - Operating Income (Loss) 22 - (5) 393 376 Interest Expense n/a 4 93 102 5 Depreciation & Amortization 13 - - 153 140 Segment Assets 4,452 399 6 (447) 4,410 Expenditures for Assets 19 - 10 227 198 Deferred Tax Assets n/a - 14 2 16 --------------------------------- ------------ --------------- ---------------- ----------------- ------------------

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. Segment assets include utility plant only (excluding accumulated depreciation) for all segments. As a result, adjustments to assets include accumulated depreciation, 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. QUARTERLY FINANCIAL DATA (UNAUDITED)

Millions of Dollars -------------------------------------------------------- ----------- ------------- ------------ ------------ --------- 2001 First Second Third Fourth Quarter Quarter Quarter Quarter Annual -------------------------------------------------------- ----------- ------------- ------------ ------------ --------- Total operating revenues $499 $400 $461 $355 $1,715 Operating income 110 88 145 85 428 Net income 54 43 80 45 222 -------------------------------------------------------- ----------- ------------- ------------ ------------ --------- -------------------------------------------------------- ----------- ------------- ------------ ------------ --------- 2000 First Second Third Fourth Quarter Quarter Quarter Quarter Annual -------------------------------------------------------- ----------- ------------- ------------ ------------ --------- Total operating revenues $395 $371 $448 $455 $1,669 Operating income 109 96 155 97 457 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 -------------------------------------------------------- ----------- ------------- ------------ ------------ ---------

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED Item 7. Management's Narrative Analysis of Results of Operations......119 Item 7A. Quantitative and Qualitative Disclosures About Market Risk.....123 Item 8. Financial Statements and Supplementary Data....................124 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 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 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. Net Income Net income for the twelve months ended December 31, 2001 and 2000 was as follows: Millions of dollars 2001 2000 ------------------------------------------------------------------------------ Net income derived from: Continuing operations $14.7 $21.2 Cumulative effect of accounting change, net of taxes - 6.6 ------------------------------------------------------------------------------ Net income $14.7 $27.8 ============================================================================== Net income from continuing operations decreased approximately $6.5 million, due to reduced margin, the sale of PSNC Production Corporation to another SCANA subsidiary (see Note 4 of Notes to Consolidated Financial Statements), higher operating expenses, lower income related to merchandise and jobbing activities and increased interest expense. Reduced margin in 2001 was partially attributable to rate reductions implemented in connection with the NCUC's approval of SCANA's acquisition of PSNC and to decreases in usage resulting from the slowing economy. Higher operating expenses were primarily attributable to severance costs and increased bad debt experience arising from record high gas costs early in the year. 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 March 31 and December 31 are generally PSNC's most profitable quarters due to increased 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, 2001 $6.0 million March 31, 2001 April 1, 2001 May 3, 2001 $5.8 million June 30, 2001 July 1, 2001 August 2, 2001 $3.0 million September 30, 2001 October 1, 2001 Gas Distribution Gas distribution sales margins for 2001 and 2000, excluding the cumulative effect of accounting change in 2000, were as follows: Millions of dollars 2001 2000 Change % Change ----------------------------------------------------------------------- Operating revenues $452.6 $405.6 $47.0 11.6% Less: Cost of gas (286.1) (237.4) (48.7) 20.5% -------------------------------------------------------- Gross margin $166.5 $168.2 $(1.7) (1.0)% ======================================================================= Gas distribution sales margin for the year ended December 31, 2001 decreased as a result of a $1 million reduction in rates in each of August 2000 and 2001 related to the acquisition of PSNC by SCANA (see Note 5-D of Notes to Consolidated Financial Statements) and lower natural gas usage. Energy Marketing Effective January 1, 2001 PSNC Production Corporation and SCANA Public Service Company LLC, both of which participated in nonregulated activities such as natural gas marketing and supply management services, were sold to SCANA Energy Marketing, Inc., a subsidiary of SCANA (see Note 4), and energy marketing ceased to be a segment of PSNC's business. Energy marketing operating revenues and net income (including affiliated transactions) for the year ended December 31, 2000 were as follows: Millions of dollars ------------------------------------------------- ------------------ Operating revenues $142.9 Net income 2.0 ================================================= ================== Operation and Maintenance Expenses The $1.3 million increase in operation and maintenance expenses from 2000 is primarily due to severance costs and an increased provision for bad debt. Other Income, net Other income decreased $1.9 million for the year ended December 31, 2001 as compared to the same period in 2000 primarily due to lower revenue and income related to merchandise and jobbing activities. The sales of gas appliances in 2001 were adversely impacted by the slowing economy and record high gas prices early in the year. Interest Expense Interest expense increased $2.4 million over 2000 as a result of increased borrowings and interest expense related to the operation of Rider D (see Note 1-G of Notes to Consolidated Financial Statements). PSNC issued $150 million of medium-term notes on February 16, 2001. The proceeds from these borrowings were used to reduce short-term debt. Capital Expansion Program and Liquidity Matters PSNC's capital expansion program includes the construction of lines, systems and facilities and the purchase of related equipment. PSNC's 2002 construction budget is approximately $41 million, compared to actual construction expenditures for 2001 of $75.3 million. For the years 2003-2006, PSNC has an aggregate of $21.4 million of long-term debt maturing. These obligations and other commitments are tabulated below. Contractual Cash Obligations Less than After December 31, 2001 Total 1year 1-3 years 4-5 years 5 years ----------------- ----- ----- --------- --------- ------- (Millions of dollars) Long-term and short-term debt (including interest) $582 $26 $78 $44 $434 Operating leases 1 1 - - - Other commercial commitments 231 162 69 - - Included in other commercial commitments are estimated obligations under forward contracts for natural gas purchases. Certain of these contracts relate to regulated gas businesses; therefore, the effects of such contracts on gas costs are reflected in gas rates. The forward contracts for natural gas purchases include customary "make-whole" or default provisions, but are not considered to be "take-or-pay" contracts. Financing Limits and Related Matters PSNC's issuance of various securities including long-term and short-term debt is subject to customary approval or authorization by state and Federal regulatory bodies including the NCUC, the SEC and FERC. The following paragraphs describe the financing programs currently utilized by PSNC. PSNC finances its operations and capital needs through short-term and long-term borrowings, including, from time-to-time, advances from SCANA. On February 16, 2001, PSNC issued $150 million of medium term notes due February 15, 2011. In late 2001 PSNC entered into two interest rate swap agreements to pay variable rates and receive fixed rates on a combined notional amount of $44.9 million. (See Note 10 of Notes to Consolidated Financial Statements.) PSNC utilitizes no off-balance sheet financings or similar arrangements other than incidental operating leases, generally for office furniture and equipment. 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 levels and other factors. Legislation or regulatory action at the Federal level, particularly as part of a larger energy policy initiative, may be considered in 2002. 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. CRITICAL ACCOUNTING POLICIES AND NEW ACCOUNTING STANDARDS SFAS 71 - PSNC is subject to the provisions of SFAS 71, which requires it to record certain assets and liabilities that defer the recognition of expenses and revenues to future periods as a result of being rate-regulated. Aside from other impacts which might be experienced as a result of deregulation or other significant changes in the regulatory environments of the utilities, SFAS 71 could cease to be applicable and PSNC could be required to write off such regulatory assets and liabilities. Provisions for bad debts / Allowances for doubtful accounts - As of each balance sheet date, PSNC evaluates the collectibility of accounts receivable and records allowances for doubtful accounts based on estimates of the level of actual write-offs which might be experienced. These estimates are based on, among other things, comparisons of the relative age of accounts and consideration of actual write-off history. Goodwill amortization and impairment analysis - SFAS 141, "Business Combinations," and SFAS 142, "Goodwill and Other Intangible Assets," were issued during 2001. SFAS 141 will require all future acquisitions to be accounted for utilizing the purchase method. PSNC considers the amounts categorized by FERC as "acquisition adjustments" to be goodwill as defined in SFAS 142 and has ceased amortization of such amounts upon the adoption of SFAS 142 effective January 1, 2002. In 2001 the amount of such amortization expense recorded was $13 million. This amortization related to an acquisition adjustment of approximately $466 million. As required by the provisions of SFAS 142, PSNC is performing an initial valuation analysis to determine whether this carrying amount is impaired and, if so, the amount of any write-down which might be recorded as the cumulative effect of the change in accounting principle. As allowed by the Statement, PSNC will have completed the initial stage of the analysis by June 30, 2002. If a write-down is indicated by the analysis, it will be quantified and recorded by the end of 2002. Because PSNC is in the early stages of the analysis, the effect, if any, of the adoption of the impairment provisions of the Statement is not known; however, if a write-down is considered necessary, it could be material to PSNC's results of operations for 2002. SFAS 143, "Accounting for Asset Retirement Obligations," provides guidance for recording and disclosing a liability related to the future obligation to retire an asset. PSNC will adopt SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on PSNC's results of operations, cash flows or financial position has not been determined but could be material. The provisions of SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," are effective January 1, 2002. This Statement requires that one accounting model be used for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired, and broadens the presentation of discontinued operations to include more disposal transactions. There was no impact on PSNC's financial statements from the initial adoption of SFAS 144. 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, 2001 Expected Maturity Date Millions of dollars Liabilities 2002 2003 2004 2005 2006 Thereafter Total Fair Value ---------------------------------- --------- ---------- ---------- ---------- ---------- ----------- ---------- ------------ Long-Term Debt: Fixed Rate ($) 4.3 7.5 7.5 3.2 3.2 269.2 294.9 298.4 Average Fixed Interest Rate 10.0 9.47 9.47 8.75 8.75 7.0 7.2 Interest Rate Swap: Pay Variable/Receive Fixed ($) - - 12.9 - - 32.0 44.9 (0.1) Average Pay Interest Rate - - 7.82 - - 5.26 6.00 Average Receive Interest Rate - - 10.0 - - 8.75 9.10 December 31, 2000 Expected Maturity Date Millions of dollars Liabilities 2001 2002 2003 2004 2005 Thereafter Total Fair 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%

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........................................ 124 Consolidated Financial Statements: Consolidated Balance Sheets as of December 31, 2001 and 2000.......... 126 Consolidated Statements of Income for the Years Ended December 31, 2001 and 2000, the Three Months Ended December 31, 1999 and the Fiscal Year Ended September 30, 1999..... 127 Consolidated Statements of Cash Flows for the Years Ended December 31, 2001 and 2000, the Three Months Ended December 31, 1999 and the Fiscal Year Ended September 30, 1999.... 128 Consolidated Statements of Capitalization as of December 31, 2001 and 2000......................................... 129 Consolidated Statements of Common Equity for the Years Ended December 31, 2001 and 2000, the Three Months Ended December 31, 1999 and the Fiscal Year Ended September 30, 1999..... 130 Notes to Consolidated Financial Statements..............................131 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, 2001 and 2000, and the related Consolidated Statements of Income, Common Equity and of Cash Flows for the years then ended 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 these financial statements and financial statement schedule based on our audits. The consolidated financial statements of the Company for the fiscal year ended September 30, 1999 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 consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2001 and 2000, and the results of its operations and its cash flows for the years then ended 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 consolidated 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 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 8, 2002 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 ---------------------------------------------------------------------------- ------------------------ -------------------------- December 31, (Millions of dollars) 2001 2000 ---------------------------------------------------------------------------- ------------------------ -------------------------- Assets Gas Utility Plant (Note 1) $855 $787 Less accumulated depreciation 288 263 Acquisition adjustment, net of accumulated amortization (Notes 1 & 3) 439 452 ---------------------------------------------------------------------------- ------------------------ -------------------------- Gas Utility Plant, Net 1,006 976 ---------------------------------------------------------------------------- ------------------------ -------------------------- Nonutility Property and Investments, Net 29 34 ---------------------------------------------------------------------------- ------------------------ -------------------------- Current Assets: Cash and temporary investments (Note 1) 18 8 Restricted cash and temporary investments (Note 1) 5 2 Receivables (net of allowance for uncollectible accounts of $1.4 for 2001 and $2.4 for 2000) 70 144 Receivables - affiliated companies 12 4 Inventories (at average cost): Stored gas 47 32 Materials and supplies 8 7 Other - 2 ---------------------------------------------------------------------------- ------------------------ -------------------------- Total Current Assets 157 202 ---------------------------------------------------------------------------- ------------------------ -------------------------- Deferred Charges and Other Assets: Due from affiliate-pension asset (Note 6) 11 10 Regulatory assets 11 21 Other 7 10 ---------------------------------------------------------------------------- -------------------------- ------------------------ Total Deferred Charges and Other Assets 29 41 ---------------------------------------------------------------------------- -------------------------- ------------------------ Total $1,221 $1,253 ============================================================================ ======================== ========================== ============================================================================ ========================== Capitalization and Liabilities Capitalization: Common equity $715 $712 Long-term debt, net (Notes 7 & 10) 290 145 ------------------------ ---------------------------------------------------------------------------- ------------------------ -------------------------- Total Capitalization 1,005 857 ---------------------------------------------------------------------------- ------------------------ -------------------------- ------------------------ Current Liabilities: Short-term borrowings (Notes 8 & 10) - 125 Current portion of long-term debt (Note 7) 4 4 Accounts payable 41 82 Accounts payable - affiliated companies 10 2 Taxes accrued 5 3 Customer prepayments and deposits 17 8 Advances from parent - 44 Dividends declared and interest accrued 6 5 Other 3 6 ---------------------------------------------------------------------------- ------------------------ -------------------------- ------------------------ Total Current Liabilities 86 279 ---------------------------------------------------------------------------- ------------------------ -------------------------- ------------------------ Deferred Credits and Other Liabilities: Deferred income taxes, net (Notes 1 & 9) 86 82 Deferred investment tax credits (Notes 1 & 9) 2 3 Due to affiliate-postretirement benefits (Note 6) 11 10 Regulatory liabilities 14 - Other 17 22 ---------------------------------------------------------------------------- ------------------------ -------------------------- Total Deferred Credits and Other Liabilities 130 117 ---------------------------------------------------------------------------- ------------------------ -------------------------- Commitments and Contingencies (Note 11) - - ---------------------------------------------------------------------------- ------------------------ -------------------------- Total $1,221 $1,253 ============================================================================ ======================== ==========================

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONSOLIDATED STATEMENTS OF INCOME ------------------------------------------------------------------- -------------------------------- ------------------------------- Successor Predecessor ------------------------------------------------------------------- -------------------------------- ----------------- ------------- Three Months Year Ended Ended Year Ended December 31, December 31, September 30, Millions of dollars 2001 2000 1999 1999 ------------------------------------------------------------------- ---------------- --------------- ----------------- ------------- Operating Revenues (Note 1 & 2) $453 $547 $81 $298 Cost of Gas 286 375 41 133 ------------------------------------------------------------------- ---------------- --------------- ----------------- ------------- Gross Margin 167 172 40 165 ------------------------------------------------------------------- ---------------- --------------- ----------------- ------------- Operating Expenses: Operation and maintenance 69 67 18 71 Depreciation and amortization (Note 1) 43 42 7 26 Other taxes 6 6 2 15 ------------------------------------------------------------------- ---------------- --------------- ----------------- ------------- Total Operating Expenses 118 115 27 112 ------------------------------------------------------------------- ---------------- --------------- ----------------- ------------- Operating Income 49 57 13 53 Other Income, net 6 8 1 6 Interest Charges, net 22 20 5 18 ------------------------------------------------------------------- ---------------- --------------- ----------------- ------------- Income Before Income Taxes and Cumulative Effect of Accounting Change 33 45 9 41 Income Taxes (Note 9) 18 24 4 17 ------------------------------------------------------------------- ---------------- --------------- ----------------- ------------- Income Before Cumulative Effect of Accounting Change 15 21 5 24 Cumulative Effect of Accounting Change, net of taxes (Note 2) - 7 - - ------------------------------------------------------------------- ---------------- --------------- ----------------- ------------- ------------------------------------------------------------------- ---------------- --------------- ----------------- ------------- Net Income 15 28 5 24 =================================================================== ================ =============== ================= =============

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONSOLIDATED STATEMENTS OF CASH FLOWS ----------------------------------------------------------------- ---------------------------------- ------------------------------- Successor Predecessor ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------ Three Months Year Ended Ended Year Ended December 31, December 31, September 30, Millions of dollars 2001 2000 1999 1999 ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------ Cash Flows From Operating Activities: Net income $15 $28 $5 $24 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 50 47 8 29 Excess distributions (undistributed earnings) of 3 (3) (1) (1) investee Gain on sale of assets - (1) - - Over (under) collection, fuel adjustment clause 23 7 1 (5) Change in certain assets and liabilities: (Increase) decrease in receivables, net 54 (70) (45) (4) (Increase) decrease in inventories (15) (3) - (5) (Increase) decrease in regulatory assets 1 (5) - (3) Increase (decrease) in accounts payable and advances (68) 78 25 5 Increase (decrease) in accrued pension cost - - (1) (3) Increase (decrease) in deferred income taxes, net 3 3 - 8 Other, net 14 - - 4 ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------ Net Cash Provided From (Used In) Operating Activities 80 74 (8) 49 ----------------------------------------------------------------- ----------------- ---------------- ------------ ------------------ Cash Flows From Investing Activities: Construction expenditures (75) (39) (12) (44) Increase in investments - (1) - (9) Proceeds on sale of assets 1 8 - - Nonutility and other - - 1 5 ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------ Net Cash Used In Investing Activities (74) (32) (11) (48) ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------ Cash Flows From Financing Activities: Proceeds from issuance of common stock - - - 6 Proceeds from issuance of medium-term notes 148 - - - Capital contribution from parent 3 - - - Retirement of long-term debt and common stock (4) (9) (8) (17) Dividend payments on common stock (18) (21) (5) (20) Short-term borrowings, net ( 125) (13) 34 34 ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------ Net Cash Provided From (Used In) Financing Activities 4 (43) 21 3 ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------ Net Increase (Decrease) in Cash and Temporary Investments 10 (1) 2 4 Cash and Temporary Investments at Beginning of Period 8 9 7 3 ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------ ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------ Cash and Temporary Investments at End of Period $18 $8 $9 $7 ================================================================= ================= ================ ================== ============ Supplemental Cash Flow Information: Cash paid during the period for: Interest (net of capitalized interest of $1.2, $1.0, $0.1 and $0.6) $16 $21 $5 $18 Income taxes 12 25 - 7

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 a $466 million acquisition adjustment. Effective January 1, 2001 PSNC Production Corporation and SCANA Public Service Company LLC were sold to SCANA Energy Marketing, Inc., an affiliate, for $4.4 million, which approximated net book value. Assets transferred included approximately $4.0 million in cash. See Notes to Consolidated Financial Statements.

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONSOLIDATED STATEMENTS OF CAPITALIZATION ------------------------------------------------------------------------------------ -------------- --------------- December 31, (Millions of dollars) 2001 2000 ------------------------------------------------------------------------------------ -------------- --------------- Common Equity: Common stock, $1 par, 1,000 shares authorized and issued in 2001 and 2000 - - Capital in excess of par value $706 $703 Retained earnings 9 9 -------------- ------------------------------------------------------------------------------------ -------------- --------------- Total Common Equity 715 712 ------------------------------------------------------------------------------------ -------------- --------------- -------------- Long-term Debt: Senior debentures (unsecured): 10% due 2004 12 17 8.75% due 2012 32 32 6.99% due 2026 50 50 7.45% due 2026 50 50 Medium-term notes: 6.625% due 2011 150 - ------------------------------------------------------------------------------------ -------------- --------------- -------------- 294 149 Less - Current maturities (4) (4) -------------- ------------------------------------------------------------------------------------ -------------- --------------- Total Long-Term Debt, Net 290 145 ------------------------------------------------------------------------------------ -------------- --------------- ------------------------------------------------------------------------------------ -------------- --------------- Total Capitalization $1,005 $857 ==================================================================================== ============== ===============

See Notes to Consolidated Financial Statements. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONSOLIDATED STATEMENTS OF COMMON EQUITY

Capital Total Millions of dollars Common Stock in Excess Retained Common Shares Amount of Par Earnings Equity --------------------------------------------- --------------- --------- -------------- ------------ --------------- Balance at September 30, 1998 20,274,332 $20 $133 $70 $223 Issuance of Stock 303,635 1 6 7 Net Income 24 24 Cash Dividends Declared (21) (21) --------------------------------------------- --------------- --------- -------------- ------------ --------------- Balance at September 30, 1999 20,577,967 21 139 73 233 Net Income 5 5 Cash Dividends Declared (6) (6) --------------------------------------------- --------------- --------- -------------- ------------ --------------- Balance at December 31, 1999 20,577,967 21 139 72 232 Cancellation of Shares Due to Acquisition (20,576,967) (21) 564 (72) 471 Net Income 28 28 Cash Dividends Declared (19) (19) --------------------------------------------- --------------- --------- -------------- ------------ --------------- Balance at December 31, 2000 1,000 - 703 9 712 Capital Contributions From Parent 3 3 Net Income 15 15 Cash Dividends Declared (15) (15) --------------------------------------------- --------------- --------- -------------- ------------ --------------- --------------------------------------------- --------------- --------- -------------- ------------ Balance at December 31, 2001 1,000 $- $706 $9 $715 ============================================= =============== ========= ============== ============ ===============

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 (Company), a public utility, was organized as a North Carolina corporation in 1938. Effective January 1, 2000 the acquisition of the Company by SCANA Corporation (SCANA), a South Carolina holding company, was consummated in a business combination accounted for as a purchase. As a result, the Company became a wholly owned subsidiary of SCANA, incorporated under the laws of South Carolina. The Company is engaged predominantly in the purchase, sale, transportation and distribution of natural gas to residential, commercial and industrial customers in North Carolina. The accompanying Consolidated Financial Statements include the accounts of the Company and its subsidiary companies, Clean Energy Enterprises, Inc., PSNC Blue Ridge Corporation, and PSNC Cardinal Pipeline Company (collectively, the "Company"). In periods prior to 2001, the accounts of PSNC Production Corporation are also included. Similarly, in 2000 the accounts of SCANA Public Service Company LLC are included. PSNC Production Corporation and SCANA Public Service Company LLC were sold to SCANA Energy Marketing, Inc., a subsidiary of SCANA, effective January 1, 2001 (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. 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, 2001, approximately $10.6 million and $14.2 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax liabilities of approximately $.4 million. The regulatory 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 National Association of Regulatory Utility Commissioners (NARUC) and as adopted by the North Carolina Utilities Commission (NCUC). D. Change in Fiscal Year The Company 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 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 7.0 percent and 6.8 percent for the years ended December 31, 2001 and 2000, respectively, 6.4 percent for the three months ended December 31, 1999 and 5.5 percent for the fiscal year ended September 30, 1999. 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.) Unbilled revenues totaled approximately $20.2 million and $48.4 million as of December 31, 2001 and 2000, respectively. The Company'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, with interest. Additionally, the Company can recover its margin losses on negotiated gas sales to certain large commercial/industrial customers in any manner authorized by the NCUC. Pursuant to the operation of Rider D, the Company had overcollected from customers approximately $13.8 million at December 31, 2001 and undercollected from customers approximately $9.3 million at December 31, 2000. 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. The Company 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 for utility plant assets were 4.1 percent for the years ended December 31, 2001 and 2000, 4.1 percent for the three months ended December 31, 1999 and 3.9 percent for the fiscal year ended September 30, 1999. The acquisition adjustment related to the purchase of the Company by SCANA is being amortized over a 35-year period using the straight-line method. The Company adopted SFAS 142, "Goodwill and Other Intangible Assets," on January 1, 2002. See Note 1M for further discussion. I. Income Taxes The Company is included in the consolidated Federal income tax return of SCANA Corporation for 2001 and 2000. 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. Also, under provisions of the income tax allocation agreement, tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including PSNC, in the form of capital contributions. In 2001 capital contributions of $3.1 million were received by PSNC under such provisions. J. Debt Expense The Company amortizes issuance costs for its debentures over the life of the related debt. The Company 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 The Company maintains an environmental assessment program to identify and evaluate current and former operation 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 cleanup 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 The Company 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, the Company 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 the Company's general funds and will be used for expansion of the Company'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 included approximately $4.5 million in supplier refunds which was 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 record high natural gas prices during early 2001. M. New Accounting Standards SFAS 141, "Business Combinations," and SFAS 142, "Goodwill and Other Intangible Assets," were issued during 2001. SFAS 141 will require all future acquisitions to be accounted for utilizing the purchase method. The Company considers the amounts categorized by FERC as "acquisition adjustments" to be goodwill as defined in SFAS 142 and has ceased amortization of such amounts upon the adoption of SFAS 142 effective January 1, 2002. In 2001, the amount of such amortization expense recorded was $13 million. This amortization related to the acquisition adjustment of approximately $466 million carried on the books of the Company. As required by the provisions of SFAS 142, the Company is performing an initial valuation analysis to determine whether this carrying amount is impaired and, if so, the amount of any write-down which might be recorded as the cumulative effect of the change in accounting principle. As allowed by the Statement, the Company will have completed the initial stage of the analysis by June 30, 2002. If a write-down is indicated by the analysis, it will be quantified and recorded by the end of 2002. Because the Company is in the early stages of the analysis, the effect, if any, of the adoption of the impairment provisions of the Statement is not known; however, if a write-down is considered necessary, it could be material to the Company's results of operations for 2002. SFAS 143, "Accounting for Asset Retirement Obligations," provides guidance for recording and disclosing a liability related to the future obligation to retire an asset (such as a nuclear plant). The Company will adopt SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on the Company's results of operations, cash flows or financial position has not been determined but could be material. The provisions of SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," are effective January 1, 2002. This Statement requires that one accounting model be used for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired, and broadens the presentation of discontinued operations to include more disposal transactions. There was no impact on the Company's financial statements for the initial adoption of SFAS 144. N. Reclassifications Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2001. 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 the Company changed its method of accounting for operating revenues from cycle billing to full accrual. The cumulative effect of this change was $6.6 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. Also, effective January 1, 2000, the gas costs associated with unbilled revenues 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 year ended September 30, 1999, the impact on that year's net income would not have been material. 3. ACQUISITION BY SCANA CORPORATION On February 10, 2000 the acquisition of the Company by SCANA was consummated in a business combination accounted for as a purchase. As a result the Company became a wholly owned subsidiary of SCANA. Pursuant to the Agreement and Plan of Merger, Company shareholders were paid approximately $212 million in cash and 17.4 million shares of SCANA common stock valued at approximately $488 million. The Company has recorded a utility plant acquisition adjustment of approximately $466 million, which reflects the excess of SCANA's purchase price of approximately $700 million over the fair value of the Company'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, 2001 and 2000 reflects the effect of this acquisition adjustment. Adoption of SFAS 142 effective January 1, 2002 has resulted in the cessation of this amortization ($13 million per year) and requires the periodic determination as to whether the carrying value has suffered an impairment in value. As described in Note 1M, the Company will determine whether there is an indication of an impairment by June 30, 2002 and will record an impairment charge, if warranted, via a cumulative effect adjustment, by the end of 2002. In connection with the acquisition, severance benefits of approximately $5.0 million have been paid to nine key executives. In addition, approximately $3.1 million was paid to former directors of the Company in connection with deferred compensation and retirement plans, and approximately $8.1 million was paid to participants in the Company'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 the Company, purchased the remaining 50% membership interest in Sonat Public Service Company L.L.C. (Sonat) for $5.3 million. As a result, Sonat became a wholly owned subsidiary of PSNC Production. Sonat was subsequently renamed SCANA Public Service Company LLC (SCANA Public Service). Effective January 1, 2001 PSNC Production and SCANA Public Service were sold to SCANA Energy Marketing, Inc., a subsidiary of SCANA, for $4.4 million, which approximated their net book value. 5. RATE AND OTHER REGULATORY MATTERS A. The Company's rates are established using a benchmark 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 the Company's pipeline transporters. The Company 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 the Company's gas purchasing practices annually. The Company's benchmark cost of gas in effect during the years ended December 2001 and 2000 was as follows: Rate Per Therm Effective Date Rate Per Therm Effective Date $.690 January 2001 $.300 January 2000 $.750 February-March 2001 $.265 February-May 2000 $.650 April-August 2001 $.350 June 2000 $.500 September-October 2001 $.450 July-September 2000 $.350 November-December 2001 $.490 October-December 2000 B. On April 6, 2000 the NCUC issued an order permanently approving the Company's request to establish its commodity cost of gas for large commercial and industrial customers on the basis of market prices for natural gas. This mechanism allows the Company to collect from its customers amounts approximating the amounts paid for natural gas. C. A state expansion fund, established by the North Carolina General Assembly in 1991 and funded by refunds from the Company's interstate pipeline transporters, provides financing for expansion into areas that otherwise would not be economically feasible to serve. On December 30, 1999 the Company filed an application with the NCUC to extend natural gas service to Madison, Jackson and Swain Counties, North Carolina. On June 29, 2000 the NCUC approved the Company's requests for disbursement of up to $28.4 million from the Company's expansion fund for this project. The Company estimates that the cost of this project will be approximately $31.4 million. The Madison County portion of the project was completed at a cost of approximately $5.8 million and customers began receiving service in July 2001. D. On December 7, 1999 the NCUC issued an order approving SCANA's acquisition of the Company. As specified in the NCUC order, the Company reduced its rates by approximately $1 million in each of August 2000 and August 2001, and agreed to a moratorium on general rate cases until August 2005. General rate relief can be obtained during this period to recover costs associated with materially adverse governmental actions and force majeure events. E. On February 22, 1999 the NCUC approved the Company'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 . Most of Alexander County lies within the Company's certificated service territory and did not previously have natural gas service. The project was completed at a cost of approximately $4.8 million, and customers began receiving natural gas service in March 2000. 6. EMPLOYEE BENEFIT PLANS AND STOCK COMPENSATION PLANS Employee Benefit Plans Since July 1, 2000 the Company has participated in SCANA's noncontributory defined benefit pension plan, which covers substantially all permanent employees. SCANA's pension plan benefits for the Company 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, the Company 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 the Company 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 the Company 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, the Company 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 12. The fair value of the Company'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, the Company's pension and postretirement plans were merged with SCANA's plans. At the time of the plan mergers, the Company 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, the Company's net periodic benefit income was approximately $0.6 million for the pension plan and the Company's net periodic benefit cost was approximately $0.7 million for the postretirement plan. For the years ended December 31, 2001 net periodic benefit income was approximately $1.2 million for the pension plan and the Company's net periodic benefit cost was approximately $2.0 million for the postretirement plan.

Disclosures required for these plans under SFAS 132, "Employer's Disclosures about Pensions and Other Postretirement Benefits," for relevant periods prior to the Plan mergers, are set forth in the following tables: Components of Net Periodic Benefit Cost: Retirement Benefits Other Postretirement Benefits ------------------------------------ ----------------------------------- 6 months 3 months 6 months 3 months ended ended Fiscal ended ended Fiscal June 30, Dec. 31, Year June 30, Dec. 31, Year Millions of Dollars 2000 1999 1999 2000 1999 1999 ---- - ---- ---- ---- - ---- ---- Service Cost $0.8 $ 0.5 $ 2.3 $ 0.1 $ 0.1 $ 0.3 Interest Cost 1.6 0.8 3.0 0.4 0.2 0.6 Expected return on plan assets (2.2) (0.8) (3.1) n/a n/a n/a Prior Service Cost Amortization - 0.1 0.6 - - 0.1 Transition Amount Amortization - (0.1) (0.3) - - 0.2 ------ - ----- ------ ------ - ------ - --- --- Net periodic benefit cost $0.2 $ 0.5 $ 2.5 $ 0.5 $ 0.3 $ 1.2 ==== ===== == ===== ===== ===== ===== Assumptions: Retirement Benefits Other Postretirement Benefits -------------------------------------------- --------------------------------------- 6 months 3 months 6 months 3 months ended ended Fiscal ended ended Fiscal June 30, Dec. 31, Year June 30, Dec. 31, Year 2000 1999 1999 2000 1999 1999 ---- ---- ---- ---- ---- ---- Discount rate 8.00 % 8.00 % 7.50 % 8.00 % 8.00 % 7.50 % Expected return on plan assets 9.50 % 9.50 % 8.00 % n/a n/a n/a Rate of compensation increase Age-related Age-related Age-related Age-related Age-related Age-related Changes in Benefit Obligations: Retirement Benefits Other Postretirement Benefits -------------------------------------- --------------------------------------- 6 months 3 months 6 months 3 months ended ended Fiscal ended ended Fiscal June 30, Dec. 31, Year June 30, Dec. 31, Year Millions of Dollars 2000 1999 1999 2000 1999 1999 ---- ---- ---- ---- ---- ---- Benefit Obligation, beginning of period $38.7 $44.1 $46.6 $ 8.9 $9.3 $9.0 Service Cost 0.8 0.5 2.3 0.1 - 0.3 Interest Cost 1.6 0.8 3.0 0.4 0.2 0.6 Settlement payments - - (7.2) n/a n/a n/a Benefits paid (2.5) (2.2) (0.5) (0.3) (0.1) (0.6) Curtailment gain - - (1.2) - - (0.3) Actuarial (gain) loss 1.3 (4.5) 1.1 2.1 (0.5) 0.3 --- --- --- ---- --- --- ---- --- - ---- -- --- Benefit Obligation at end of period $39.9 $38.7 $44.1 $ 11.2 $8.9 $9.3 ===== ===== ===== ====== ==== ====

Change in Plan Assets: Retirement Benefits ------------------------------------------------------------------- 6 months ended 3 months ended Fiscal June 30, Dec. 31, Year 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 Other Postretirement Benefits ------------------------------------- --------------------------------------- 6 months 3 months 6 months 3 months ended ended Fiscal ended ended Fiscal June 30, Dec. 31, Year June 30, Dec. 31, Year Millions of Dollars 2000 1999 1999 2000 1999 1999 ---- ---- ---- ---- ---- ---- Funded status, beginning of period $6.3 $9.2 $0.9 $(11.2) $(8.9) $(9.3) Unrecognized actuarial (gain) loss 2.7 (14.4) (7.6) 2.1 (0.5) 0.3 Unrecognized prior service cost - 2.5 2.7 - 0.4 0.4 Unrecognized transition obligation - (0.8) (1.0) - 2.7 2.8 ----- - -- ---- -- ---- ------ -- --- --- ---- --- Net amount recognized $9.0 $(3.5) $(5.0) $(9.1) $(6.3) $(5.8) ==== ====== = ====== ====== ====== ======

Health Care Trends The determination of net periodic other postretirement benefit cost is based on the following assumptions. 6 months ended June 3 months ended Fiscal Year 30, 2000 Dec. 31, 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 the Company effective January 1, 2000, the Company sponsored the stock-based compensation plans described below. The Company 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 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 as reported of $24.5 million for the year ended September 30, 1999 would have been reduced to the pro forma amount of $23.7 million. Nonqualified Stock Option Plans The Company 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 the Company common stock could have been granted to officers and key employees of the Company 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 the Company 's common stock could have been granted to officers and key employees of the Company 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 the Company's acquisition by SCANA, all outstanding options became exercisable on July 1, 1999. No options were granted under the plans subsequent to fiscal year 1998. Options exercised and canceled under both plans for the periods indicated were as follows: Options Weighted-Average Outstanding Exercise Price ------------------------------------------------------------------------------ September 30, 1998 955,684 $18.46 Exercised (149,212) $14.66 Canceled (101,680) $20.54 --------------------------------------------------------- September 30, 1999 704,792 $18.97 Exercised (60,647) $12.86 --------------------------------------------------------- December 31,1999 644,145 $19.08 Exercised (644,145) $19.08 --------------------------------------------------------- December 31, 2000 and 2001 - - ========================================================= 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, the Company 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 the Company issued 62,355 shares to employees. 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 --------------------------------------------- ---------------------- Risk free interest rate 4.58% Volatility factor 14.96% Dividend yield 3.85% Expected life 1 year The weighted average fair value of each employee stock purchase plan grant during fiscal 1999 was $6.52. 7. LONG-TERM DEBT The annual amounts of long-term debt maturities for the years 2002 through 2006 are summarized as follows: ------------------- ----------------- ------------------ ----------------- Year Amount Year Amount ------------------- ----------------- ------------------ ----------------- (Millions of Dollars) 2002 $4.3 2005 $3.2 2003 7.5 2006 3.2 2004 7.5 ------------------- ----------------- ------------------ ----------------- On February 16, 2001 the Company issued $150 million of medium-term notes having an annual interest rate of 6.625 percent and maturing on February 15, 2011. The proceeds were used to reduce short-term debt and for general corporate purposes. 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, 2001, the Company is in compliance in all material respects with the requirements of its debt agreements. 8. SHORT-TERM BORROWINGS Millions of dollars 2001 2000 ----------------------------------------------------------- --------------- Authorized lines of credit $125.0 $125.0 Unused lines of credit $125.0 $125.0 Short-term borrowings outstanding: Commercial paper (270 days or less) - $125.0 Weighted average interest rate n/a 6.69% The Company pays fees to banks as compensation for its committed lines of credit. 9. INCOME TAXES Total income tax expense attributable to income (before cumulative effect of accounting change) for 2001, 2000 and 1999 is as follows:

Three Months Year Ended Ended Year Ended December 31, December 31, September 30, 2001 2000 1999 1999 ---------------------------------------------------- ----------------- ---------------- ----------------- --------------- (Millions of Dollars) Current taxes: Federal $14.0 $18.6 $2.9 $9.0 State 3.0 3.9 0.6 2.1 ---------------------------------------------------- ----------------- ---------------- ---------------- ---------------- ---------------------------------------------------- ----------------- ---------------- ---------------- ---------------- Total current taxes 17.0 22.5 3.5 11.1 ---------------------------------------------------- ----------------- ---------------- ---------------- ---------------- ---------------------------------------------------- ----------------- ---------------- ---------------- ---------------- Deferred taxes, net: Federal 1.2 1.5 0.6 5.4 State 0.3 0.3 0.1 1.2 ---------------------------------------------------- ----------------- ---------------- ---------------- ---------------- ---------------------------------------------------- ----------------- ---------------- ---------------- ---------------- Total deferred taxes 1.5 1.8 0.7 6.6 ---------------------------------------------------- ----------------- ---------------- ---------------- ---------------- ---------------------------------------------------- ----------------- ---------------- ---------------- ---------------- Investment tax credits: Amortization of amounts deferred - Federal (0.3) (0.4) - (0.4) ---------------------------------------------------- ----------------- ---------------- ---------------- ---------------- Total investment tax credits (0.3) (0.4) - (0.4) ---------------------------------------------------- ----------------- ---------------- ---------------- ---------------- Total income tax expense $18.2 $23.9 $4.2 $17.3 ==================================================== ================= ================ ================ ================

The difference between actual income tax expense and the amount calculated from the application of the statutory 35 percent Federal income tax rate to pre-tax income (before cumulative effect of accounting change) is reconciled as follows:

Three Months Twelve Months Year Ended Ended Ended December 31, December 31, September 30, 2001 2000 1999 1999 ------------------------------------------------------------- ----------- ------------ --------------- --------------- Income before cumulative effect of accounting change $14.8 $21.2 $5.1 $24.1 Total income tax expense: Charged to operating expense 15.7 20.6 3.8 15.3 Charged to other income 3.3 0.4 2.0 2.5 ------------------------------------------------------------- ----------- ------------ --------------- --------------- Total pre-tax income $33.0 $45.1 $9.3 $41.4 ============================================================= =========== ============ =============== =============== ============================================================= =========== ============ =============== =============== Income taxes on above at statutory Federal income tax rate $11.6 $15.8 $3.3 $14.5 Increases (decreases) attributed to: State income taxes (less Federal income tax effect) 2.1 2.8 0.5 2.1 Non-deductible book amortization of acquisition 4.7 4.7 - - adjustments Amortization of Federal investment tax credits - (0.4) (0.3) (0.4) Other differences, net 0.1 1.0 0.4 1.1 ------------------------------------------------------------- ----------- ------------ --------------- --------------- ------------------------------------------------------------- ----------- ------------ --------------- --------------- Total income tax expense $18.2 $23.9 $4.2 $17.3 ============================================================= =========== ============ =============== ===============

The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $85.8 million at December 31, 2001 and $80.7 million at December 31, 2000 are as follows:

---------------------------------------------------------------------------------- ---------------- ------------------ 2001 2000 ---------------------------------------------------------------------------------- ---------------- ------------------ (Millions of Dollars) Deferred tax assets: Unamortized investment tax credits $1.0 $1.0 Other 0.5 2.9 ---------------------------------------------------------------------------------- ---------------- ------------------ Total deferred tax assets 1.5 3.9 ---------------------------------------------------------------------------------- ---------------- ------------------ Deferred tax liabilities: Property, plant and equipment 85.2 82.2 Other 2.1 2.4 ---------------------------------------------------------------------------------- ---------------- ------------------ Total deferred tax liabilities 87.3 84.6 ---------------------------------------------------------------------------------- ---------------- ------------------ Net deferred tax liability $85.8 $80.7 ================================================================================== ================ ==================

10. FINANCIAL INSTRUMENTS The carrying amounts and estimated fair values of the Company's financial instruments at December 31, 2001 and 2000 are as follows:

Millions of dollars 2001 2000 --------------------------------------------- ----------------------------- ------------------------------ Estimated Estimated Carrying Fair Carrying Fair Amount Value Amount Value --------------------------------------------- -------------- -------------- --------------- -------------- Assets: Cash and temporary cash investments $18 $18 $8 $8 Liabilities: Short-term borrowings - - 125 125 Long-term debt 294 298 149 154

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 amount. o Fair values of 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. The carrying values reflect the fair values of interest rate swaps based on settlement values obtained from counterparties. 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. Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. SFAS 133 requires the Company to recognize all derivative instruments as either assets or liabilities in the statement of financial position and to measure those instruments at fair value. SFAS 133 further provides that changes in fair value of derivative instruments are either recognized in earnings or reported as other comprehensive income, depending upon the intended use of the derivative and the resulting designation. The impact on the Company of adopting SFAS 133 was not material. In December 2001 the Company entered into a two interest rate swap agreements to pay variable rates and receive fixed rate interest payments on a combined notional amount of $44.9 million. These swaps were designated as fair value hedges of the Company's $12.9 million, 10% senior debenture due 2004 and $32.0 million, 8.75% senior debenture due 2012. The fair value of these interest rate swaps is reflected within other deferred debits on the balance sheet. The corresponding hedge debt is also marked to market on the balance sheet. The receipts or payments related to the interest rate swaps are credited or charged to interest expense as incurred. 11. COMMITMENTS AND CONTINGENCIES A. The Company owns, or has owned, all or portions of seven sites in North Carolina on which manufactured gas plants (MGPs) were formerly operated. Intrusive investigation (including drilling, sampling and analysis) has begun at two sites, 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 Company estimates that the cost to remediate the sites would range between $11.3 million and $21.9 million. The estimated cost range has not been discounted to present value. The Company'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 (PRPs). At December 31, 2001 the Company has recorded a liability and associated regulatory asset of $9.1 million, which reflects the minimum amount of the range, net of shared cost recovery expected from other PRPs and expenditures for work completed. Amounts incurred to date are approximately $1.1 million. Management believes that all costs incurred will be recoverable through gas rates. B. 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. C. Purchase commitments under forward contracts for natural gas purchases are $162 million and $69 million in 2002 and 2003, respectively. 12. RESTRUCTURING During fiscal 1999, the Company 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. 13. SEGMENT OF BUSINESS INFORMATION For the year ended December 31, 2001 Gas Distribution is the Company's sole reportable segment. Subsidiaries whose operations comprised the Energy Marketing segment were sold to an affiliate effective January 1, 2001 (see Note 4). 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). Gas distribution uses operating income to measure profitability. The Company did not have deferred tax assets for any period reported. Interest income was not significant. 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 All Adjustments/ Consolidated December 31, 2001 Distribution Other Eliminations Total ------------------------------- ------------------- --------------- ------------------------- ------------------- External Revenue $453 - - $453 Intersegment Revenue - - - - Deprec. & Amort. 43 - - 43 Operating Income 49 n/a - 49 Interest Expense 22 - - 22 Segment Assets 1,184 29 8 1,221 Expenditures for Assets 75 - - 75 ------------------------------- ------------------- ---------------- -------------- -------------------- ------------------ 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 1,235 35 72 (89) 1,253 Expenditures for Assets 39 - - - 39 ------------------------------- ------------------- ---------------- -------------- -------------------- ------------------ 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 - - 12 ------------------------------- ------------------- -------------------- -------------------- ------------------- Fiscal Year Ended Gas All Adjustments/ Consolidated September 30, 1999 Distribution Other Eliminations Total ------------------------------- ------------------- -------------------- -------------------- ------------------- External Revenue $298 $6 $(6) $298 Intersegment Revenue - 39 (39) - Deprec. & Amort. 26 1 26 (1) Operating Income 53 n/a - 53 Interest Expense 18 - - 18 Net Income n/a 2 22 24 Segment Assets 637 46 (34) 649 Expenditures for Assets 44 - - 44

14. QUARTERLY FINANCIAL DATA (UNAUDITED)

Millions of dollars --------------------------------------------------------- ------------ ----------- ----------- ----------- ----------- 2001 First Second Third Fourth Quarter Quarter Quarter Quarter Annual --------------------------------------------------------- ------------ ----------- ----------- ----------- ----------- Total operating revenues $228 $67 $47 $111 $453 Operating income (loss) 39 (2) (9) 21 49 Net income (loss) 20 (5) (10) 10 15 ---------------------------------------------------------- ----------- ----------- ----------- ----------- ----------- 2000 First Second Third Fourth Quarter Quarter Quarter Quarter Annual ---------------------------------------------------------- ----------- ----------- ----------- ----------- ----------- Total operating revenues $171 $80 $76 $220 $547 Operating income (loss) 37 (2) (7) 29 57 Cumulative effect of accounting change, net of taxes 7 - - - 7 Net income (loss) 26 (5) (8) 15 28

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: None PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT SCANA: The other information required by Item 10 is incorporated herein by reference, to the captions "Election of Directors: Proposal 1 - Nominees For Class III Directors", "Continuing Directors", and "Other Information - Section 16(a) Beneficial Ownership Reporting Compliance" in SCANA's definitive proxy statement for the 2002 annual meeting of shareholders which was filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934. 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 shareholders, 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 are for SCANA Corporation and all subsidiaries unless otherwise indicated.

Name Age Positions Held During Past Five Years Dates ---- --- ------------------------------------- ----- W. B. Timmerman 55 Chairman of the Board, President and Chief Executive Officer *-present H. T. Arthur 56 Senior Vice President, General Counsel and Assistant Secretary 1998-present Vice President, General Counsel and Assistant Secretary *-1998 G. J. Bullwinkel 53 Senior Vice President, Governmental Affairs and Economic Development 1999-present President and Chief Operating Officer, SCI 1997-present Senior Vice President - Retail Electric, SCE&G *-1999 S. A. Byrne 42 Senior Vice President-Nuclear Operations, SCE&G 2001-present Vice President-Nuclear Operations, SCE&G 2000-2001 General Manager Nuclear Plant Operations, SCE&G *-2000 A. H. Gibbes 55 President and Chief Operating Officer, SCPC *-present President and Treasurer, SCANA Development Corp. *-present D. C. Harris 49 Senior Vice President of Human Resources 2000-present Vice President Human Resources, Austin Quality Foods, Inc., Cary, NC *-2000 N. O. Lorick 51 President and Chief Operating Officer, SCE&G 2000-present Vice President - Fossil and Hydro Operations, SCE&G *-2000 K. B. Marsh 46 President and Chief Operating Officer, PSNC 2001-present Senior Vice President and Chief Financial Officer 1998-present Vice President - Finance, Chief Financial Officer *-1998 Controller *-2000 A. M. Milligan 42 Senior Vice President - Marketing 1998-present President and Chief Operating Officer, SCANA Resources, Inc. 2001-present President, SCANA Resources, Inc. 1999-2001 Director of Consumer Credit Marketing, Barnett Bank, N. A., FL *-1998 J. E. Addison 41 Vice President - Finance 2002-present Vice President - SCANA Services, Inc. 2000-2002 Vice President and Controller, SCE&G *-2000 M. R. Cannon 51 Controller 2000-present Treasurer, SCANA and all subsidiaries (excluding SCPC) *-2000 * Indicates position held at least since March 1, 1997.

SCE&G: DIRECTORS The directors listed below were elected May 3, 2001 (except as otherwise indicated) to hold office until the next annual meeting of SCE&G's shareholders on May 2, 2002. Name and Year First Age Principal Occupation; Directorships Became Director Bill L. Amick 58 For more than five years, Chairman of the Board and Chief Executive Officer of Amick Farms, (1990) Inc., Amick Processing, Inc. and Amick Broilers, Inc., Batesburg, SC (vertically integrated broiler operation). Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC; Blue Cross and Blue Shield of South Carolina, Columbia, SC. James A. Bennett 41 Since May 2000, President and Chief Executive Officer of South Carolina Community Bank, (1997) Columbia, SC. From February 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. 60 For more than five years, a partner in Bookhart Farms, Elloree, SC (general farming). (1979) Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC. William C. Burkhardt 64 Retired since May 2000. (2000) From 1980 until May 2000, President and Chief 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 and Industrial Microwave Systems, Raleigh, NC. Hugh M. Chapman 68 Since June 30, 1997, retired from NationsBank South, Atlanta, GA (a division of (1988) 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 66 For more than five years, Executive Director of ETV Endowment of South Carolina, Inc. (1992) (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. Name and Year First Age Principal Occupation; Directorships Became Director Lawrence M. Gressette, Jr. 69 Since February 28, 1997, Chairman Emeritus, SCANA Corporation, Columbia, SC. (1987) For more than five years prior to February 28, 1997, Chairman of the Board and Chief Executive Officer, SCANA Corporation. Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC. D. Maybank Hagood 40 For more than five years, President and Chief Executive Officer of William M. Bird and (1999) Company, Inc., Charleston, SC (wholesale distributor of floor covering materials). Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC. W. Hayne Hipp 62 For more than five years, Chairman, and Chief Executive Officer, The Liberty (1983) Corporation, Greenville, SC (broadcasting holding company). Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC; The Liberty Corporation, Greenville, SC. Lynne M. Miller 50 Since February 1998, Chief Executive Officer of Environmental Strategies Corporation, (1997) 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. Maceo K. Sloan 52 For more than five years, Chairman, President and Chief Executive Officer of Sloan Financial (1997) Group, Inc. (holding company) and Chairman and Chief Executive Officer of NCM Capital Management Group, Inc. (investment management company), Durham, NC. Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC; M&F Bankcorp, Inc., and its subsidiary, Mechanics and Farmers Bank, Durham, NC; and Trustee of Teachers Insurance Annuity Association - College Retirement Equity Fund (TIAA- CREF). Harold C. Stowe 55 Since March 1997, President and Chief Executive Officer of Canal Holdings, LLC and its (1999) predecessor company, Conway, SC (forest products industry). Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC; Canal Holdings, LLC, Conway, SC; Ruddick Corporation, Charlotte, NC. William B. Timmerman 55 Since March 1997, Chairman of the Board and Chief Executive Officer, SCANA (1991) Corporation, Columbia, SC. Since December 1995, President, SCANA Corporation. Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC; ITC^DeltaCom, Inc., West Point, GA; The Liberty Corporation, Greenville, SC. G. Smedes York 61 For more than five years, President and Treasurer of York Properties, Inc., Raleigh, NC. (2000) (full-service commercial and residential real estate company). 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 55 Chairman of the Board and Chief Executive Officer *-present H. T. Arthur 56 Senior Vice President, General Counsel and Assistant Secretary 1998-present Vice President, General Counsel and Assistant Secretary *-1998 S. A. Byrne 42 Senior Vice President-Nuclear Operations 2001-present Vice President-Nuclear Operations 2000-2001 General Manager Nuclear Plant Operations *-2000 N. O. Lorick 51 President and Chief Operating Officer 2000-present Vice President - Fossil and Hydro Operations *-2000 K. B. Marsh 46 Senior Vice President - Finance and Chief Financial Officer 1998-present Vice President - Finance and Chief Financial Officer *-1998 Controller *-2000 M. R. Cannon 51 Controller 2000-present Treasurer *-2000

*Indicates position held at least since March 1, 1997 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 2001 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 2002 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 Payouts -------------- ----------- Securities Other Underlying All Annual Option/ LTIP Other Year Salary Bonus(1) Compensation(2) SARS Payouts(3) Compensation(4) Name and Principal Position ($) ($) ($) (#) ($) ($) ------------------------------------ ------ ------------- ----------- ------------------ -------------- ----------- --------------- W. B. Timmerman 2001 660,238(5) 17,611 129,781 60,884 - - Chairman, President and Chief 2000 524,261 354,486 17,888 35,620 50,230 - Executive Officer - SCANA 1999 490,313 312,900 17,212 - 298,813 29,419 N. O. Lorick 2001 385,252 18,701 36,711 30,611 - President and Chief Operating 2000 167,778 124,921 7,313 2,332 12,728 - Officer - SCE&G 1999 157,417 44,356 7,313 - 38,754 9,445 K. B. Marsh 2001 334,234 10,554 36,711 29,097 - - Senior Vice President 2000 276,172 150,720 10,613 11,627 24,254 - and Chief Financial Officer - 1999 241,354 128,058 10,337 - 81,555 14,481 SCANA H. T. Arthur 2001 270,963 16,119 19,142 23,487 - - Senior Vice President and 2000 234,812 120,480 16,119 8,796 19,718 - General Counsel 1999 219,806 93,825 15,939 - 65,843 13,188 S. A. Byrne 2001 244,232 9,465 19,142 22,064 - - Senior Vice President-Nuclear 2000 183,555 123,492 8,310 8,796 12,962 - Operations 1999 137,321 32,483 3,600 - 8,239 - ------------------------------------ ------ ------------- ----------- ------------------ -------------- ----------- ---------------

(1) Payments under the Annual Incentive Plan. (2) For 2001, 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 $1,176 for Mr. Timmerman; $10,250, $7,959 and $492 for Mr. Lorick; $9,000, $1,183 and $371 for Mr. Marsh; $9000, $6,830 and $289 for Mr. Arthur and $9,000, $180 and $285 for Mr. Byrne. (3) Payments under the Long-term Equity Compensation Plan. (4) All other compensation for all executive officers consists solely of Company matching contributions to defined contribution plans. (5) Reflects actual salary paid in 2001. Base salary of $676,300, became effective on February 3, 2001.

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 129,781 18.12 27.45 2-22-11 2,240,021 5,677,919 N. O. Lorick 36,711 5.12 27.45 2-22-11 633,632 1,606,106 K. B. Marsh 36,711 5.12 27.45 2-22-11 633,632 1,606,106 H. T. Arthur 19,142 2.67 27.45 2-22-11 330,451 837,429 S. A. Byrne 19,142 2.67 27.45 2-22-11 330,451 837,429

All the above options vest 33 1/3 percent on each of the first, second and third anniversaries of the date of the grant, February 22, 2001. 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 11,873/153,528 27,664/104,648 N. O. Lorick 777/38,266 1,810/17,573 K. B. Marsh 3,875/44,463 9,029/32,012 H. T. Arthur 2,932/25,006 6,832/20,937 S. A. Byrne 2,932/25,006 6,832/20,937 (1)Based on the closing price of $27.83 per share on December 31, 2001, the last trading date of the fiscal year. The following table lists the performance share awards made in 2001 (for potential payment in 2004) 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 20,132 2001-2003 8,053 20,132 30,198 N. O. Lorick 5,695 2001-2003 2,278 5,695 8,543 K. B. Marsh 5,695 2001-2003 2,278 5,695 8,543 H. T. Arthur 2,969 2001-2003 1,188 2,969 4,454 S. A. Byrne 2,969 2001-2003 1,188 2,969 4,454 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 cash or a combination of stock and cash. DEFINED BENEFIT PLANS SCANA has a tax qualified defined benefit retirement plan. The plan has a mandatory cash balance benefit formula (the "Cash Balance Formula") for employees hired on or after January 1, 2000. 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 the cash balance benefit option. All the executive officers named in the Summary Compensation Table elected to participate under the cash balance option of the plan. The Cash Balance Formula benefit is expressed in the form of a hypothetical account balance. Employees electing to participate under the cash balance option had an opening account balance established for them. The opening account balance was equal to 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 average 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 officers. A SERP is an unfunded plan that provides for benefit payments in addition to benefits payable under the qualified Retirement Plan in order to replace benefits lost in the Retirement Plan because of Internal Revenue Code maximum benefit limitations. 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 - $427,476; Mr. Lorick - $282,696; Mr. Marsh - $311,556; Mr. Arthur - $111,024 and Mr. Byrne - $238,440. 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 holds SCANA contributions (if made) which may be used to pay the deferred and other 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). The current executive officers included in the Summary Compensation Table participate in all the plans listed below which are covered by the trust. (1) SCANA Corporation Executive Deferred Compensation Plan (2) SCANA Corporation Supplemental Executive Retirement Plan (3) SCANA Corporation Long-Term Equity Compensation Plan (4) SCANA Corporation Annual Incentive Plan (5) SCANA Corporation Key Executive Severance Benefits Plan (6) SCANA Corporation Supplementary Key Executive Severance Benefits Plan The Key Executive Severance Benefits Plan and each of the plans listed under (1) through (4) provide for payment of benefits in a lump sum to the eligible participants immediately upon a Change in Control, unless the Key Executive Severance Benefits Plan is terminated prior to the Change in Control. In contrast, the Supplementary Key Executive Severance Benefits Plan is operative for a period of 24 months following a Change in Control where the Key Executive Severance Benefits Plan is inoperative because it was terminated before the Change in Control. The Supplementary Key Executive Severance Benefits Plan provides benefits in lieu of those otherwise provided under plans (1) through (4) if: (i) the participant is involuntarily terminated from employment without "Just Cause," or (ii) the participant voluntarily terminates 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, include an amount equal to estimated federal, state and local income taxes and any estimated applicable excise taxes owned by the plan participants on those benefits. The benefit distributions under the Key Executive Severance Benefits Plan would include the following three benefits: o An amount equal to three times the sum of: (i) the participant's annual base salary in effect as of the Change in Control and (ii) the officer's target annual incentive award in effect as of the Change in Control under the Annual Incentive Plan. o An amount equal to the projected cost for medical, long-term disability and certain life insurance coverage for three years following the Change in Control as though the participant had continued to be a SCANA employee. o An amount equal to the participant's Supplemental Executive Retirement Plan benefit accrued to the date of the Change in Control, increased by the present value of projected benefits that would otherwise accrue under the plan (based on the plan's actuarial assumptions) assuming that the participant remained employed until reaching age 65 and offset by the value of the participant's Retirement Plan benefit. Additional benefits payable upon a Change in Control where the Key Executive Severance Benefits Plan is operable are: o A benefit distribution of all amounts credited to the participant's Executive Deferred Compensation Plan account 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, if any. o Under the Long-Term Equity Compensation Plan, all nonqualified stock options awarded would 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. The benefits and their respective amounts, when the Supplementary Key Executive Severance Benefits Plan is operable, would be the same except that the benefits payable with respect to the Executive Deferred Compensation Plan would be increased by the prime rate published in the Wall Street Journal most nearly preceding the date of the Change in Control plus three percent (3 percent) calculated until the end of the month preceding the month in which the benefits are distributed. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION During 2001, 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. Director 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 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 Since January 1, 2001, non-employee director compensation deferrals have been governed by 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 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 may also 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. During 2001, Messrs. Amick, Bennett, Burkhardt, Hipp, Sloan, Stowe and York and Ms. Miller elected to defer 100 percent of their compensation and earnings under the Director Compensation and Deferral Plan so as to acquire hypothetical shares of SCANA Common Stock. In addition, Mr. Hagood elected to defer 60 percent of his annual retainer and earnings under the plan 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 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 2002 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 February 28, 2002 by each director, each nominee and each executive officer named in the Summary Compensation table on page 152. SECURITY OWNERSHIP OF MANAGEMENT Amount and Nature Amount and Nature of Beneficial Ownership of of Beneficial Ownership of Name SCANA Common Stock of SCANA Common *(1)(2)(3)(4)(5) Name Stock *(1) (2) (3)(4) (5) ----- -------------------------------- --------------------------------- B. L. Amick 10,896 D. M. Hagood 822 H. T. Arthur 26,292 W. H. Hipp 4,897 J. A. Bennett 2,286 N. O. Lorick 29,604 W. B. Bookhart, Jr. 21,725 K. B. Marsh 35,778 W. C. Burkhardt 11,626 L. M. Miller 3,417 S. A. Byrne 17,163 M. K. Sloan 4,132 H. M. Chapman 8,212 H. C. Stowe 4,127 E. T. Freeman 6,184 W. B. Timmerman 122,257 L. M. Gressette, Jr. 63,858 G. S. York 11,225 *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 (21 persons) TOTAL 415,642. TOTAL PERCENT OF CLASS, outstanding and entitled to vote at the Annual Meeting of Shareholders 0.4 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-6,064; Mr. Gressette-1,060; and by all directors, nominees and executive officers 7,604 in total. (2) Includes shares purchased through February 28, 2002, 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 February 28, 2002, each of the following directors had acquired under the plan, the number of hypothetical shares following his/her name: Messrs. Amick-3,280, Bennett-3,945, Burkhardt-3,902, Hagood-1,359, Hipp-3,635, Sloan-3,485, Stowe-3,245 and York-3,645 and Ms. Miller-3,822. (4) Includes shares subject to currently exercisable options and options that will become exercisable within 60 days in the following amounts: Mr. Timmerman-67,007; Mr. Lorick-13,792; Mr. Marsh-19,988; Mr. Byrne-12,245; Mr. Arthur-12,245. (5)Hypothetical shares acquired under the SCANA Executive Deferred Compensation Plan are not included in the above table. As of February 28, 2002, each of the following officers had acquired under the plan, the number of hypothetical shares following his/her name: Messrs. Timmerman-15,402; Lorick-1,638; Marsh-3,410; Mr. Byrne-1,031; Mr. Arthur-2,241. 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 shareholders. 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 2002 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 2001, SCANA paid $120,983 (including the value of non-utility in kind services provided by SCANA) to subsidiaries of The Liberty Corporation for advertising expenses. Mr. Hipp is Chairman and Chief Executive Officer and a director of The 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 159. (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 2001 for SCANA, SCE&G and PSNC: None

SCANA: Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2001, 2000 and 1999. 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 2001 30,533,701 10,452,458 - 3,988,732 36,997,427 2000 7,302,273 25,574,187 - 2,342,759 30,533,701 1999 1,965,732 7,604,493 - 2,267,952 7,302,273 Reserve for investment impairment 2001 4,928,768 - 4,928,768 - - 2000 4,133,768 1,000,000 - 205,000 4,928,768 1999 10,292,611 - 6,158,843 4,133,768 - Reserves other than those deducted from assets on the balance sheet: Reserve for injuries and damages 2001 7,349,339 264,849 - 1,762,900 5,851,288 2000 5,221,544 2,461,339 - 333,544 7,349,339 1999 4,287,986 1,352,448 - 418,890 5,221,544 Provision for decontamination and decommissioning 2001 6,355,795 503,330 - 6,859,125 - 2000 6,487,365 - - 131,570 6,355,795 1999 6,256,249 231,116 - 6,487,365 - Provision for environmental remediation and settlement 2001 2,814,569 - - 420,382 2,394,187 2000 3,223,821 - - 409,252 2,814,569 1999 3,619,572 - - 395,751 3,223,821

SCE&G: Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2001, 2000 and 1999.

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 2001 577,000 3,273,754 - 3,030,754 820,000 2000 537,000 2,381,626 - 2,341,626 577,000 1999 611,001 2,048,370 - 2,122,371 537,000 Reserves other than those deducted from assets on the balance sheet: Reserve for injuries and damages 2001 4,575,192 - - 1,154,138 3,421,054 2000 3,972,816 819,431 - 217,055 4,575,192 1999 4,176,794 104,000 - 307,978 3,972,816 Provision for decontamination and decommissioning 2001 2,814,569 - - 420,382 2,394,187 2000 3,223,821 - - 409,252 2,814,569 1999 3,619,572 - - 395,751 3,223,821

PSNC: Schedule II - Valuation and Qualifying Accounts for the Years Ended December 31, 2001 and 2000, the Three Months Ended December 31, 1999 and the Fiscal Year Ended September 30, 1999.

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 2001 2,402,696 4,158,568 - 1,444,719 5,116,.545(a) 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(b) Fiscal Year 1999 2,086,128 725,094 - 1,073,407 1,737,815 Reserves other than those deducted from assets on the balance sheet: Reserve for injuries and damages 2001 1,626,258 723,628 - 1,148,761 1,201,125 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 Provision for post-retirement & post-employment 2001 398,000 - 398,000 - - 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

(a)Includes $309,645 uncollectible reserve balance for SCANA Public Service Company LLC which was sold to SCANA Energy Marketing effective January 1, 2001. (b)Ending balance for December 31, 1999 includes $294,235 uncollectible reserve balance for SCANA Public Service Company LLC (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, 2002 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 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. *Signed on behalf of each of these persons by Kevin B. Marsh, Attorney-in-Fact DATE: March 27, 2002 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, 2002 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 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. *Signed on behalf of each of these persons by Kevin B. Marsh, Attorney-in-Fact DATE: March 27, 2002 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/Kevin B. Marsh. Kevin B. Marsh, President and Chief Operating Officer DATE: March 27, 2002 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 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. *Signed on behalf of each of these persons by Kevin B. Marsh, Attorney-in-Fact DATE: March 27, 2002 EXHIBIT INDEX Exhibit Applicable to Form 10-K of No. SCANA SCE&G PSNC Description 2.01 X X 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 incorporated by reference herein) 3.01 X 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 herein) 3.02 X Articles of Amendment of SCANA, dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. 33-62421 and incorporated by reference herein) 3.03 X Restated Articles of Incorporation of SCE&G, as adopted on May 3, 2001 (Filed as Exhibit 3.01 to Registration Statement No. 333-65460 and incorporated by reference herein) 3.04 X Articles of Amendment of SCE&G, dated May 22, 2001 (Filed as Exhibit 3.02 to Registration Statement No. 333-65460 and incorporated by reference herein) 3.05 X Articles of Correction of SCE&G, dated June 1, 2001 (Filed as Exhibit 3.03 to Registration Statement No. 333-65460 and incorporated by reference herein) 3.06 X Articles of Amendment of SCE&G, dated June 14, 2001 (Filed as Exhibit 3.04 to Registration Statement No. 333-65460 and incorporated by reference herein) 3.07 X Articles of Amendment of SCE&G, dated August 30, 2001 (Filed as Exhibit 3.07 to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein) 3.08 X 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 reference herein) 3.09 X 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 incorporated by reference herein) 3.10 X Articles of Correction of PSNC dated February 11, 2000 (Filed as Exhibit 3.03 to Registration Statement No. 333-45206 and incorporated by reference herein) 3.11 X Articles of Amendment of SCE&G, dated March 13, 2002 (Filed herewith) 3.12 X By-Laws of SCANA as revised and amended on December 13, 2000 (Filed as Exhibit 3.01 to Registration Statement No. 333- 68266 and incorporated by reference herein) 3.13 X By-Laws of SCE&G as amended and adopted on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333- 65460 and incorporated by reference herein) 3.14 X By-Laws of PSNC (formerly New Sub II, Inc.) as revised and amended on February 22, 2001 (Filed as Exhibit 3.01 to Registration Statement No. 333-68516 and incorporated by reference herein) EXHIBIT INDEX Exhibit Applicable to Form 10-K of No. SCANA SCE&G PSNC Description 4.01 X X Articles of Exchange of South Carolina Electric & Gas Company and SCANA Corporation (Filed as Exhibit 4-A to Post-Effective Amendment No. 1 to Registration Statement No. 2-90438 and incorporated by reference herein) 4.02 X 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 by reference herein) 4.03 X X 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 by reference herein) 4.04 X X 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. 2-26459 and incorporated by reference herein) 4.05 X X 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 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. 33-38580 -------- June 1, 1981 Exhibit 4-D to Registration No. 33-49421 -------- March 1, 1982 Exhibit 4-D to Registration No. 2-73321 -------- 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. 33-49421 -------- May 1, 1999 Exhibit 4.04 to Registration No. 333-86387 -------- -------- 4.06 X X Indenture dated as of April 1, 1993 from South Carolina Electric & Gas Company to NationsBank of Georgia, National Association (Filed as Exhibit 4-F to Registration Statement No. 33-49421 and incorporated by reference herein) -------- 4.07 X X 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 incorporated by reference herein) -------- 4.08 X X 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 incorporated by reference herein) -------- 4.09 X X Trust Agreement for SCE&G Trust I (Filed as Exhibit 4.03 to Registration Statement No. 333-49960 and incorporated by reference herein) -------- 4.10 X X Certificate of Trust of SCE&G Trust I (Filed a Exhibit 4.04 to Registration Statement No. 333-49960 and incorporated by reference herein) -------- 4.11 X X Junior Subordinated Indenture for SCE&G Trust I (Filed as Exhibit 4.05 to Registration Statement No. 333-49960 and incorporated by reference herein) -------- 4.12 X X Guarantee Agreement for SCE&G Trust I (Filed as Exhibit 4.06 to Registration Statement No. 333-49960 and incorporated by reference herein) -------- 4.13 X X Amended and Restated Trust Agreement for SCE&G Trust I (Filed as Exhibit 4.07 toRegistration Statement No. 333-49960 and incorporated by reference herein) -------- EXHIBIT INDEX Exhibit Applicable to Form 10-K of No. SCANA SCE&G PSNC Description 4.14 X X Indenture dated as of January 1, 1996 between PSNC and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.08 to Registration Statement No. 333-45206 and incorporated by reference herein) -------- 4.15 X X First Supplemental Indenture dated as of January 1, 1996, between PSNC and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.09 to Registration Statement No. 333-45206 and incorporated by reference herein) -------- 4.26 X X 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. 333-45206 and incorporated by reference herein) -------- 4.27 X X 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 Registration Statement No. 333-45206 and incorporated by reference herein) 4.28 X X Fourth Supplemental Indenture dated as of February 12, 2001 between PSNC and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.05 to Registration Statement No. 333-68516 and incorporated by reference herein) -------- 4.29 X PSNC $150 million medium-term note issued February 16, 2001 (Filed as Exhibit 4.06 to Registration Statement No. 333-68516 and incorporated by reference herein) -------- 10.01 X SCANA Executive Deferral Compensation Plan as amended July 1, 2001 (Filed as Exhibit 10.01 to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein) -------- 10.02 X SCANA Supplementary Executive Retirement Plan as amended July 1, 2001 (Filed as Exhibit 10.02 to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein) -------- 10.03 X SCANA Key Executive Severance Benefits Plan as amended July 1, 2001 (Filed as Exhibit 10.03 to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein) -------- 10.04 X SCANA Supplementary Key Severance Benefits Plan as amended July 1, 2001 (Filed as Exhibit 10.03a to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein) -------- 10.05 X 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 reference herein) -------- 10.06 X SCANA Long-Term Equity Compensation Plan dated January 2000 filed as Exhibit 4.04 to Registration Statement No. 333-37398 and incorporated by reference herein) -------- EXHIBIT INDEX Exhibit Applicable to Form 10-K of No. SCANA SCE&G PSNC Description -------- 10.07 X 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 incorporated by reference herein) 10.08 X Description of SCANA Corporation Executive 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) 10.09 X SCANA Corporation Director Compensation and Deferral Plan effective January 1, 2001 (Filed as Exhibit 10.05 to Registration Statement No. 333-49960 and incorporated by reference herein) 10.10 X Operating Agreement of Pine Needle LNG Company, LLC dated August 8, 1995 (Filed as Exhibit 10.01 to Registration Statement No. 333-45206 and incorporated by reference herein) 10.11 X Amendment to Operating Agreement of Pine Needle LNG Company, LLC dated October 1, 1995 (Filed as Exhibit 10.02 to Registration Statement No. 333-45206 and incorporated by reference herein) 10.12 X Amended Operating Agreement of Cardinal Extension Company, LLC dated December 19, 1996 (Filed as Exhibit 10.03 to Registration Statement No. 333-45206 and incorporated by reference herein) 10.13 X 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 reference herein) 10.14 X 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 herein) 10.15 X 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 reference herein) 10.16 X X Service Agreement between SCE&G and SCAN Services, Inc., effective April 1, 2001 (Filed as Exhibit 10.16 to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein) 12.01 X X X Statement Re Computation of Ratios 23.01 X Consents of Experts and Counsel (Independent Auditors' Consent) 23.02 X Consents of Experts and Counsel (Independent Auditors Consent) 23.03 X Consents of Experts and Counsel (Independent Auditors Consent) 23.04 X Consents of Experts and Counsel (Consent of Independent Public Accountants) 24.01 X X X Power of Attorney (Filed herewith) 99.01 X Representation by Independent Public Accountants