10-Q 1 formq2nd.txt FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 FORM 10-Q (X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 2002 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 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 the number of shares outstanding of each of the issuer's classes of common stock, as of the last practicable date. Description of Shares Outstanding Registrant Common Stock at July 31, 2002 ---------- ------------ ------------------------- SCANA Corporation Without Par Value 104,732,446 South Carolina Electric & Gas Company Par Value $4.50 Per Share 40,296,147 (a) Public Service Company of North Carolina, Incorporated Without Par Value 1,000 (a) (a)Held beneficially and of record by SCANA Corporation. This combined Form 10-Q 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 H (1)(a) and (b) of Form 10-Q and therefore is filing this form with the reduced disclosure format allowed under General Instruction H(2). ================================================================================ 2 INDEX Page PART I. FINANCIAL INFORMATION SCANA Corporation Financial Section........................................ 3 Item 1. Financial Statements Condensed Consolidated Balance Sheets as of June 30, 2002 and December 31, 2001 ...................... 4 Condensed Consolidated Statements of Operations for the Periods Ended June 30, 2002 and 2001.............. 6 Condensed Consolidated Statements of Cash Flows for the Periods Ended June 30, 2002 and 2001.............. 7 Condensed Consolidated Statements of Comprehensive Income (Loss) for the Periods Ended June 30, 2002 and 2001............................... 8 Notes to Condensed Consolidated Financial Statements......... 9 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.............................. 19 Item 3. Quantitative and Qualitative Disclosures About Market Risk....... 28 South Carolina Electric & Gas Company Financial Section................... 30 Item 1. Financial Statements Condensed Consolidated Balance Sheets as of June 30, 2002 and December 31, 2001 .................... 31 Condensed Consolidated Statements of Income for the Periods Ended June 30, 2002 and 2001............... 33 Condensed Consolidated Statements of Cash Flows for the Periods Ended June 30, 2002 and 2001......... 34 Notes to Condensed Consolidated Financial Statements......... 35 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations....................................... 40 Item 3. Quantitative and Qualitative Disclosures About Market Risk........ 45 Public Service Company of North Carolina, Incorporated Financial Section... 46 Item 1. Financial Statements Condensed Consolidated Balance Sheets as of June 30, 2002 and December 31, 2001 ..................... 47 Condensed Consolidated Statements of Operations for the Periods Ended June 30, 2002 and 2001................ 48 Condensed Consolidated Statements of Cash Flows for the Periods Ended June 30, 2002 and 2001............... 49 Notes to Condensed Consolidated Financial Statements.............. 50 Item 2. Management's Narrative Analysis of Results of Operations.......... 54 PART II. OTHER INFORMATION Item 1. Legal Proceedings.................................................. 56 Item 4. Submission of Matters to a Vote of Security-Holders................ 56 Item 6. Exhibits and Reports on Form 8-K................................... 57 Signatures.................................................................. 58 Exhibit Index............................................................... 61 SCANA CORPORATION FINANCIAL SECTION PART I. FINANCIAL INFORMATION Item 1. Financial Statements SCANA CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) -------------------------------------------------------------------------------- June 30, December 31, Millions of dollars 2002 2001 -------------------------------------------------------------------------------- Assets Utility Plant: Electric $5,154 $4,855 Gas 1,543 1,536 Other 195 187 -------------------------------------------------------------------------------- Total 6,892 6,578 Accumulated depreciation and amortization (2,440) (2,364) -------------------------------------------------------------------------------- Total 4,452 4,214 Construction work in progress 478 544 Nuclear fuel, net of accumulated amortization 50 45 Acquisition adjustments, net of accumulated amortization 460 460 -------------------------------------------------------------------------------- Utility Plant, Net 5,440 5,263 -------------------------------------------------------------------------------- Nonutility Property, Net of Accumulated Depreciation 89 93 Investments 191 191 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- Nonutility Property and Investments, Net 280 284 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- Current Assets: Cash and temporary investments 404 212 Receivables (net of allowance for uncollectible accounts of $33 in 2002 and $37 in 2001) 381 424 Inventories (at average cost): Fuel 138 164 Materials and supplies 60 59 Emission allowances 13 13 Prepayments 31 21 Investments 170 664 -------------------------------------------------------------------------------- Total Current Assets 1,197 1,557 -------------------------------------------------------------------------------- Deferred Debits: Environmental 31 34 Nuclear plant decommissioning fund 83 79 Pension asset, net 252 239 Other regulatory assets 223 210 Other 162 156 -------------------------------------------------------------------------------- Total Deferred Debits 751 718 -------------------------------------------------------------------------------- Total $7,668 $7,822 ================================================================================ SCANA CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) -------------------------------------------------------------- ----------------- June 30, December 31, Millions of dollars 2002 2001 -------------------------------------------------------------- ----------------- Capitalization and Liabilities Stockholders' Investment: Common equity $2,150 $2,194 Preferred stock (Not subject to purchase or sinking funds) 106 106 -------------------------------------------------------------- ----------------- Total Stockholders' Investment 2,256 2,300 Preferred Stock, net (Subject to purchase or sinking funds) 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 50 50 Long-Term Debt, net 2,993 2,646 -------------------------------------------------------------- ----------------- Total Capitalization 5,309 5,006 -------------------------------------------------------------- ----------------- Current Liabilities: Short-term borrowings 213 165 Current portion of long-term debt 396 739 Accounts payable 237 275 Customer deposits 46 41 Taxes accrued 39 82 Interest accrued 56 45 Dividends declared 36 34 Deferred income taxes, net 30 154 Other 26 26 -------------------------------------------------------------- ----------------- Total Current Liabilities 1,079 1,561 -------------------------------------------------------------- ----------------- Deferred Credits: Deferred income taxes, net 736 720 Deferred investment tax credits 116 118 Reserve for nuclear plant decommissioning 83 79 Postretirement benefits 127 122 Other regulatory liabilities 103 100 Other 115 116 -------------------------------------------------------------- ----------------- Total Deferred Credits 1,280 1,255 -------------------------------------------------------------- ----------------- Total $7,668 $7,822 ============================================================== ================= See Notes to Condensed Consolidated Financial Statements.

See Notes to Condensed Consolidated Financial Statements. SCANA CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) -------------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30, June 30, Millions of dollars 2002 2001 2002 2001 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- Net Income (Loss) $40 $385 $(32) $464 Other Comprehensive Income (Loss), net of tax: Unrealized gains (losses) on securities available for sale (64) (247) 29 (99) Unrealized gains (losses) on hedging activities 3 (34) 27 (53) Cumulative effect of change in accounting for hedging activities - - - 23 -------------------------------------------------------------------------------- Total Comprehensive Income (Loss) (1) $(21) $104 $24 $335 ================================================================================ (1) Accumulated other comprehensive loss of the Company totaled $(57) million and $(113) million as of June 30, 2002 and December 31, 2001, respectively. See Notes to Condensed Consolidated Financial Statements. SCANA CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS June 30, 2002 (Unaudited) The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in SCANA Corporation's (the Company) Annual Report on Form 10-K for the year ended December 31, 2001. These are interim financial statements, and due to the seasonality of the Company's business, the amounts reported in the Condensed Consolidated Statements of Operations are not necessarily indicative of amounts expected for the year. In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature, which are necessary for a fair statement of the results for the interim periods reported. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. 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, "Accounting for the Effects of Certain Types of Regulation." SFAS 71 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 June 30, 2002 approximately $254 million and $103 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets, and liabilities of approximately $141 million and $90 million, respectively. The electric and gas regulatory assets of approximately $56 million and $57 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 are 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. B. New Accounting Standards The Company adopted SFAS 141, "Business Combinations," and SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002. SFAS 141 requires all acquisitions to be accounted for utilizing the purchase method. The Company considers the amounts categorized by the Federal Energy Regulatory Commission (FERC) as "acquisition adjustments" to be goodwill as defined in SFAS 142 and ceased amortization of such amounts upon the adoption of SFAS 142. This amortization is related to acquisition adjustments of approximately $466 million carried on the books of Public Service Company of North Carolina, Incorporated (PSNC) and approximately $40 million carried on the books of South Carolina Pipeline Corporation (SCPC). The Company has no other intangible assets subject to amortization as provided in SFAS 142. If the Company had ceased amortization during all periods presented in the condensed consolidated statements of operations, net income (loss) and basic and diluted earnings (loss) per share would have been as follows:

Deutsche Telekom AG (DTAG) is an international telecommunications carrier. 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). In March 2002 SCH sold 21 million ordinary shares of DTAG at a weighted average price of $14.82 per share through a series of market transactions. 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, Inc. (ITCD) is a regional provider of telecommunications services 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 June 2002 ITCD announced plans for a reorganization and entered into Chapter 11 bankruptcy. As a result the Company and SCH wrote off their investments in ITCD in the second quarter resulting in an aggregate impairment charge of approximately $7.0 million (after tax). Upon the bankruptcy court's acceptance of the reorganization plan, the Company is committed to provide up to $15 million in equity financing for ITCD. In July 2002 Knology negotiated a potential exchange of its discount notes for a combination of new notes and new preferred stock. As a result of the anticipated exchange, the Company recorded an impairment loss of approximated $0.3 million (after-tax). If the anticipated note restructuring occurs, the Company has committed to purchase an additional 6.5 million shares of series C preferred stock for approximately $19.5 million. Derivatives 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 and administrative risks assumed by the Company. The Company's Board of Directors has delegated the authority for setting market risk limits to a Risk Management Committee. 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 to other comprehensive income of approximately $23.0 million, net of tax, as the effect of a change in accounting principle (transition adjustment) 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 $2.9 million and $21.9 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the three and six months ended June 30, 2002, respectively. The Company recognized a loss of approximately $0.3 million and a gain of approximately $4.6 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the three and six months ended June 30, 2001, respectively. These gains and losses were recorded in cost of gas. The Company estimates that most of the June 30, 2002 unrealized loss balance of $0.4 million, net of tax, will be reclassified from accumulated other comprehensive income to earnings in 2002 as a realized gas cost increase if market prices remain stable. As of June 30, 2002 substantially all of the Company's cash flow hedges settle by their terms before the end of 2005. Certain derivatives that SCPC utilizes to hedge its gas purchasing activities are recoverable through its weighted average cost of gas calculation. 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 the periods presented. 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 June 30, 2002 the estimated fair value of this swap was $13.4 million. In August 2001 the Company received $6.5 million to terminate the original swap. The $6.5 million basis adjustment of the related debt is being amortized as a reduction to interest expense over the ten-year term of the $300 million medium-term notes. In December 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. At June 30, 2002 the estimated fair value of these swaps was $0.9 million. The fair value of these interest rate swaps is reflected within other deferred debits on the balance sheet. The corresponding hedged fair value change of the debt is also recorded on the balance sheet. The receipts or payments related to the interest rate swaps are credited or charged to interest expense as incurred. 6. COMMITMENTS AND CONTINGENCIES Reference is made to Note 13 of Notes to Consolidated Financial Statements appearing in the Company's Annual Report on Form 10-K for the year ended December 31, 2001. Commitments and contingencies at June 30, 2002 include the following: A. Lake Murray Dam Reinforcement In October 1999 FERC mandated that SCE&G reinforce its 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 approximately $250 million and be completed in 2005. 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 V. C. Summer Nuclear Station (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. 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 $15.5 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 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. 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 late 2002. SCE&G anticipates that major remediation activities will be completed in 2003, with certain monitoring activities continuing until 2007. As of June 30, 2002, SCE&G has spent approximately $17.9 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 before 2006. SCE&G has spent approximately $2.0 million related to these sites and expects to spend 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 the cost to remediate the sites to be 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 potentially responsible parties (PRPs). At June 30, 2002 PSNC has recorded a liability and associated regulatory asset of $8.9 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 $1.2 million. Management believes that all MGP cleanup costs will be recoverable through gas rates. D. Telecommunications Investments For a discussion of commitments related to the Company's telecommunications investments, see Note 5. 7. SEGMENT OF BUSINESS INFORMATION The Company's reportable segments are listed in the following table. The Company uses operating income to measure profitability for its regulated operations. Therefore, net income is not allocated to the Electric Operations, Gas Distribution and Gas Transmission segments. The Company uses net income to measure profitability for its Retail Gas Marketing and Energy Marketing segments. Affiliate revenue is derived from transactions between reportable segments as well as transactions between separate legal entities that are combined into the same reportable segment. Accumulated depreciation is not assignable to Electric Operations and Gas Distribution segments. Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC and meets SFAS 131 criteria for aggregation.

8. SUBSEQUENT EVENTS A. On August 2, 2002 the Company filed a registration statement with the Securities and Exchange Commission for the proposed issuance and sale of up to 6,000,000 shares of SCANA Common Stock. The offering is expected to be concluded in the fall of 2002. Net proceeds from the sale will be contributed to the equity capital of SCE&G or used for general corporate purposes. B. On August 6, 2002 SCE&G filed an application with the SCPSC requesting a $105 million increase in retail electric revenues. The electric rate request is largely associated with the power generation projects at SCE&G's recently completed Urquhart Station and the generating station currently under construction in Jasper County. It also includes costs for equipment required for environmental and air quality improvements. C. The Company is planning to issue $100 million one-year floating rate medium term notes on August 15, 2002 maturing on August 15, 2003. The interest rate on the notes is expected to be reset quarterly based on a three-month LIBOR plus 87.5 basis points. The proceeds will be used for general corporate purposes. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations ------------------------------------------------------------------------------- SCANA CORPORATION MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in SCANA Corporation's (the Company) Annual Report on Form 10-K for the year ended December 31, 2001. Statements included in this discussion and analysis (or elsewhere in this quarterly 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 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. At the Federal level, energy legislation has passed both houses of Congress in 2002, though significant differences exist between the House and Senate versions. Among other things, this legislation would require that one percent of the electric energy sold by retail electric suppliers be generated from renewable energy resources beginning in 2005. This requirement would gradually escalate to ten percent in 2019. Substantial penalties would be levied for failure to comply. Electric cooperatives and municipal utilities would be exempt from these requirements. In addition, on July 31, 2002, FERC proposed new rules aimed at creating a standard market design for wholesale electric markets. See Other Matters-Regional Transmission Organization, in this Management's Discussion and Analysis of Financial Conditions and Results of Operations. The Company is not able to predict whether these or similar legislative or regulatory actions will be enacted and, if they are, the impact they will have on the Company. Gas Transmission 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 the natural gas-fired generating station that SCE&G is building in Jasper County, South Carolina. In June 2002 SCG received preliminary approval from FERC to acquire and build a pipeline from Elba Island, Georgia to Jasper County, South Carolina. Final approval is pending. The project has an anticipated in-service date of November 2003. Retail Gas Marketing In April 2002 Georgia's Governor signed into law the Natural Gas Consumer's Relief Act of 2002 (the Act). The Act attempts to resolve many of the issues surrounding Georgia's deregulated natural gas market with the following significant provisions: o creates a regulated provider selected through a bidding process to serve low-income and high credit risk customers, o allows Georgia's 42 non-profit Electric Membership Corporations (EMC) to set up natural gas affiliates that may seek certification as marketers of natural gas, o establishes new service quality standards and addresses assignment of interstate assets, and o gives the Georgia Public Service Commission (GPSC) the authority to temporarily regulate rates if more than 90% of customers in a specific area of the state are served by three or fewer marketers. The GPSC is responsible for implementing and monitoring most of the Act's provisions. While SCANA Energy believes the Act represents a balanced approach in addressing deregulation issues for consumers and marketers, the impact the Act will have on SCANA Energy and Georgia's natural gas market cannot be predicted until more details of GPSC's implementation become known. In June 2002 SCANA Energy won GPSC approval to become the State's regulated provider. In this capacity, SCANA Energy will serve low-income customers at below-market rates subsidized by Georgia's Universal Service Fund, and it will extend service at above-market rates to high-risk customers who have been denied service by other marketers. In June 2002 the fourth largest marketer in Georgia's natural gas market declared bankruptcy. In July 2002 a subsidiary of Southern Company completed its purchase of the bankrupt marketer's Georgia operations. Southern Company, through a subsidiary, sells electricity to approximately two million customers in Georgia. Southern Company is anticipated to be a significant competitor in the Georgia natural gas market. In addition, in July 2002 one EMC applied to the GPSC to become certified as a gas marketer. 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 5 of Notes to Condensed 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 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 anticipates that its contractual cash obligations will be met through internally generated funds, the incurrence of additional short-term and long-term indebtedness and sales of additional equity securities. See Note 8 of Notes to Condensed Consolidated Financial Statements. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future. The Company's ratio of earnings to fixed charges for the 12 months ended June 30, 2002 was 1.27. On August 6, 2002 SCE&G filed an application with the Public Service Commission of South Carolina (SCPSC) requesting a $104.7 million increase in retail electric revenues. The electric rate request is largely associated with the power generation projects at SCE&G's recently completed Urquhart Station and the Jasper Generating Station currently under construction, both of which are discussed below. It also includes costs for equipment required for environmental and air quality improvements. The following table summarizes how the Company generated and used funds for property additions and construction expenditures during the six months ended June 30, 2002 and 2001: -------------------------------------------------------------------------------- Six Months Ended June 30, Millions of dollars 2002 2001 --------------------------------------------------------------- ---------------- Net cash provided from operating activities $191 $92 Net cash provided from (used for) financing activities (39) 144 Funds used for investments in equity securities (20) (28) Cash provided from sale of investments and assets 336 26 Cash and temporary investments available at the beginning of the period 212 159 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Net cash available for property additions and construction expenditures $680 $393 =============================================================================== Funds used for utility property additions and construction expenditures, Net of noncash allowance for funds used during construction $269 $183 Funds used for nonutility property additions 7 25 =============================================================================== 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. 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 on March 11, 2002 its First and Refunding Mortgage Bonds, 8 7/8 percent Series due August 15, 2021. On April 24, 2002 SCANA redeemed $202 million of floating rate medium-term notes that were set to mature on January 24, 2003. The notes were bearing interest of 2.90 percent at the time of redemption. On July 15, 2002 SCANA retired at maturity $300 million of floating rate medium-term notes. The notes were bearing interest of 4.063 percent at maturity. The Company is planning to issue $100 million one-year floating rate medium term notes on August 15, 2002 maturing on August 15, 2003. The interest rate on the notes is expected to be reset quarterly based on a three-month LIBOR plus 87.5 basis points. The proceeds will be used for general corporate purposes. SCE&G placed in service a $248 million gas turbine generator project in Aiken County, South Carolina in June 2002. Two combined-cycle turbines burn natural gas to produce 340 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. In 1999 FERC mandated that SCE&G reinforce its 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 approximately $250 million and be completed in 2005. In May 2002 SCE&G began construction of 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. The $450 million facility is expected to begin commercial operation in the summer of 2004, and SCG Pipeline, Inc., will transport natural gas to the facility. 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.

These ratings reflect the downgrade issued by Standard & Poor's on July 31, 2002. The Company does not expect the downgrade to adversely impact the Company's liquidity. ENVIRONMENTAL MATTERS For information on environmental matters see Note 6C of Notes to Condensed Consolidated Financial Statements. OTHER MATTERS Regional Transmission Organization (RTO) In June 2002 the Company and the other two electric utilities that formed GridSouth Transco LLC (GridSouth) suspended implementation of GridSouth. Though the three companies continue to support the RTO concept, GridSouth implementation was suspended pending the issuance and evaluation of new FERC directives. In July 2002 FERC issued a Notice of Proposed Rulemaking (NOPR) which further defines FERC's new standard market design for wholesale electric markets, including bidding rules and other measures to create a common market framework. The Company is currently evaluating this NOPR to determine what effect it will have on the Company's operations. Additional directives from FERC are expected later in 2002. Radio Service Network In April 2002 SCI sold its 800 Mhz radio service network within South Carolina to Motorola, Inc. for an after tax gain of approximately $9 million. Telecommunications Investments In June 2002 ITC^DeltaCom, Inc. (ITCD) announced plans for a reorganization and entered into Chapter 11 bankruptcy. As a result the Company and SCH wrote off their investments in ITCD in the second quarter (see Note 5 of Notes to Condensed Consolidated Financial Statements). Upon the bankruptcy court's acceptance of the reorganization plan, the Company is committed to provide up to $15 million in equity financing for ITCD which will result in the Company owning approximately 7% of the reorganized ITCD. In July 2002 Knology, Inc. (Knology) negotiated a potential exchange of its discount notes for a combination of new notes and new preferred stock. As a result of the anticipated exchange, the Company recorded an impairment loss of approximately $0.3 million (after-tax). If the anticipated note restructuring occurs, the Company has committed to purchase an additional 6.5 million shares of series C preferred stock for approximately $19.5 million. This purchase is expected to occur before year end, and will result in the Company owning a 13% voting interest in Knology. For more information on telecommunications investments, see Note 5 of Notes to Condensed Consolidated Financial Statements. Nuclear Station License Extension In August 2002 SCE&G filed an application with the Nuclear Regulatory Commission (NRC) for a 20-year license extension for its V. C. Summer Nuclear Station. If approved, the extension would allow the plant to operate through 2042. Transit SCE&G and the City of Columbia, South Carolina (City) have entered into an agreement under which a regional transit authority is expected to take over operation of SCE&G's transit system effective August 31, 2002. As part of the agreement, SCE&G will pay the City $32 million over seven years in exchange for a 30-year electric and gas franchise, will convey transit-related property and equipment to the City and will convey the historic Columbia Canal and Hydroelectric Plant to the City. The transaction has been approved by the SCPSC and the SEC, but is still subject to approval by FERC and other customary conditions to closing. Stock Purchase-Savings Plan Between April 17, 2002 and August 1, 2002 265,814 shares of the Company's no par value common stock ("Common Stock") were purchased in open market transactions by AMVESCAP National Trust Company as Trustee of the Company's Stock Purchase-Savings Plan (the "Plan"). These shares were purchased for the accounts of those employees of the Company and its subsidiaries that participate in the Plan. Under the terms of the Plan, employees may contribute up to 15% of their "eligible earnings" to the Plan and the Company matches the first 6% of such contributions on a dollar-for-dollar basis. The Company believes that the open market purchase of shares by the Trustee should not be deemed to be an offer or sale of securities subject to the registration requirements of the Securities Act of 1933, as amended. Nevertheless, because the matter is not free from doubt and because the Plan provides for original issue purchases as well as open market purchases, the Company filed a registration statement on August 2, 2002, on Form S-8 (333-97555) registering 5,000,000 shares of Common Stock for sale under the Plan. RESULTS OF OPERATIONS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2002 AS COMPARED TO THE CORRESPONDING PERIOD IN 2001 Earnings (Loss) Per Share Earnings (loss) per share of common stock for the second quarter and year to date periods ended June 30, 2002 and 2001 were as follows:

Second Quarter 2002 vs 2001 Earnings per share from operations increased $.07 primarily due to lower interest expense of $.05, improved margins from sales of electricity of $.04, increased allowance for funds used during construction of $.02, lower depreciation and amortization expense of $.01 and other of $.01. These factors were partially offset by higher operation and maintenance expenses of $.05 and lower gas margins of $.01. Earnings (loss) per share from non-recurring items included a $.09 gain from the sale of a subsidiary's radio service network in April 2002 and a $.07 loss due to an impairment write-down of the Company's investment in ITCD in June 2002. In May 2001 the Company recognized a non-cash gain of $3.38 from the sale of its investment in Powertel, Inc. Year to Date 2002 vs 2001 Earnings (loss) per share from operations increased $.10 primarily due to lower interest expense of $.11, improved margins from sales of electricity of $.03, lower depreciation and amortization expense of $.02, increased allowance for funds used during construction of $.05, improved results from non-regulated subsidiaries of $.04, increased tax deductions from benefit plans of $.02 and other increases of $.02. These factors were partially offset by lower gas margins of $.13, higher operation and maintenance expenses of $.04, higher property taxes of $.01 and other decreases of $.01. Earnings (loss) per share from non-recurring items includes a second quarter 2002 gain from the sale of the Company's radio service network of $.09 and loss from an impairment charge for the Company's investment in ITCD of $.07. In addition, the Company recognized a non-recurring gain of $.10 per share in connection with the sale of Deutsche Telekom AG (DTAG) ordinary shares in March 2002. In March 2002 the company also recorded an impairment write-down of $1.52 per share related to the other than temporary decline in market value of the Company's investment in DTAG (see Note 5 of Notes to Condensed Consolidated Financial Statements). In 2001 the Company recorded a gain from the sale of its investment in Powertel, Inc. of $3.38 and a gain from the sale of the assets of SCANA Security of $.04. Pension Income For the last several years, the market value of the Company's retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. Pension income in the second quarter and the year to date periods of 2002 decreased significantly compared to corresponding periods in 2001 primarily as a result of a less favorable investment market. Pension income during these periods was recorded on the Company's financial statements as follows: ------------------------------------------------------------------------------- Second Quarter Year to Date Millions of dollars 2002 2001 2002 2001 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Financial Statement Impact: Reduction in employee benefit costs $3.3 $5.2 $6.9 $10.4 Increase in other income 1.8 3.0 3.9 6.0 Reduction in capital expenditures 1.0 1.4 1.9 2.9 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Total Pension Income $6.1 $9.6 $12.7 $19.3 ====================================================================== ======== Allowance for Funds Used During Construction (AFC) AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. Both the equity and the debt portions of AFC are noncash items of nonoperating income which have the effect of increasing reported net income. AFC represented approximately 16 percent and 42 percent of income (loss) before taxes and preferred stock dividends for the three and six months ended June 30, 2002, respectively, compared to one percent for both corresponding periods in 2001. The increase in AFC is primarily the result of increased construction expenditures related to the projects at Urquhart Station, Jasper County and Lake Murray Dam (see discussion at LIQUIDITY AND CAPITAL RESOURCES) and the effect of non-recurring items on income (loss) before tax for the periods. Dividends Declared The Company's Board of Directors declared the following dividends on common stock during 2002: -------------------- --------------------- -------------------- --------------- Declaration Date Dividend Per Share Record Date Payment Date -------------------- --------------------- -------------------- --------------- February 21, 2002 $.325 March 8, 2002 April 1, 2002 May 2, 2002 $.325 June 10, 2002 July 1, 2002 August 1, 2002 $.325 September 10, 2002 October 1, 2002 -------------------- --------------------- -------------------- --------------- Electric Operations Electric Operations is comprised of the electric portion of SCE&G, South Carolina Generating Company (GENCO) and South Carolina Fuel Company (Fuel Company). Changes in the electric operations sales margins were as follows:

Second Quarter 2002 vs 2001 Margin increased due to more favorable weather. Fuel used in generation increased and purchased power cost decreased due to the repowering project at the Urquhart plant which was completed in June 2002 and higher utilization of steam plants during the planned maintenance outage at Summer Station in 2002. Year to Date 2002 vs 2001 Margin increased due to more favorable weather in the second quarter, which was partially offset by less favorable weather in the first quarter. Fuel used in generation increased and purchased power cost decreased due to more plants being on line during the period. Gas Distribution Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC. Changes in the gas distribution sales margins, including transactions with affiliates, were as follows:

Second Quarter 2002 vs 2001 Margin increased primarily due to customer growth. Revenues and gas purchases decreased as a result of lower commodity natural gas prices. Year to Date 2002 vs 2001 Margin decreased primarily due to milder weather and weak economic conditions in the first quarter, which were partially offset by customer growth in the second quarter. Revenues and gas purchases decreased as a result of lower commodity natural gas prices. Gas Transmission Gas Transmission is comprised of the operations of South Carolina Pipeline Corporation. Changes in the gas transmission sales margins, including transactions with affiliates, were as follows:

Second Quarter 2002 vs 2001 Margin increased primarily due to the favorable competitive position of natural gas relative to alternate fuels, including increased sales for electric generation. Year to Date 2002 vs 2001 Margin decreased primarily due to the unfavorable competitive position of natural gas relative to alternate fuels in the first quarter, which was partially offset by a favorable competitive position in the second quarter. 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 also includes industrial sales in the state of Georgia. Retail gas marketing revenues and net income, were as follows:

Second Quarter 2002 vs 2001 Operating revenues decreased primarily as a result of the decline in commodity natural gas prices, lower volumes and fewer customers. The change from a net loss in 2001 to net income in 2002 resulted primarily from lower bad debt expense. Year to Date 2002 vs 2001 Operating revenues decreased primarily as a result of the decline in commodity natural gas prices, lower volumes and fewer customers. Net income increased primarily due to lower bad debt expense. Energy Marketing Energy Marketing is comprised of the Company's non-regulated marketing operations, excluding SCANA Energy. Changes in energy marketing operating revenues, including transactions with affiliates, and net income (loss) were as follows:

Second Quarter 2002 vs 2001 Operating revenue decreased primarily as a result of declines in commodity natural gas prices from the record levels experienced in 2001 and due to less favorable weather than in 2001. Net income (loss) decreased primarily as a result of the closing of operations of SCANA Energy Trading, LLC during the first quarter of 2002 and the closing of the Midwest office in the third quarter of 2001. Year to Date 2002 vs 2001 Operating revenues decreased primarily as a result of declines in commodity natural gas prices from the record levels experienced in 2001 and due to less favorable weather than in 2001. Net income (loss) decreased primarily as a result of the closing of operations of SCANA Energy Trading, LLC during the first quarter of 2002 and the closing of the Midwest office in the third quarter of 2001. Other Operating Expenses Changes in other operating expenses were as follows:

Other operation and maintenance expense for the three and six months ended June 30, 2002 compared to the corresponding periods in 2001 increased primarily due to increased nuclear refueling maintenance costs, higher property insurance costs and reduced pension income in 2002. Depreciation and amortization for the three and six months decreased due to implementation of SFAS 142 and the resulting reduction in amortization expense related to goodwill (see Note 1B of Notes to Condensed Consolidated Financial Statements), which was partially offset by increases for normal property additions. Other taxes increased primarily due to increased property taxes. Other Income (Loss) Other income, including AFC, for the three and six months ended June 30, 2002 increased compared to the corresponding periods in 2001 primarily due to construction at the Urquhart Station, Jasper County and Lake Murray Dam projects. The decrease in Other Income related to gain on sale of investments and assets and the loss incurred from impairment of investments are discussed at Earnings (Loss) Per Share. Interest Expense Interest expense for the three and six months ended June 30, 2002 decreased compared to the corresponding periods in 2001 primarily due to declining interest rates on the Company's debt. Income Taxes Income taxes for the three and six months ended June 30, 2002 decreased approximately $191 million and $283 million, respectively, when compared to the corresponding periods in 2001. These decreases are primarily due to reductions of deferred income taxes in connection with the non-recurring investment impairments recorded in March and June 2002 arising from the Company's telecommunications investments (see Note 5 of Notes to Condensed Consolidated Financial Statements), which were partially offset in March and April 2002 by the sale of DTAG stock and the sale of the Company's radio service network. Item 3. 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.

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 investments in the 11.875 percent senior discount notes (due 2007) of a telecommunications company, the cost basis of which is approximately $82.1 million. See additional discussion at Other Matters - Telecommunications Investments at Management's Discussion and Analysis of Financial Condition and Results of Operations. 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. As of June 30, 2002 Millions of dollars, except weighted average settlement price and strike price

(a) Weighted average See Note 5 of Notes to Condensed Consolidated Financial Statements for additional information. 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 and administrative risks assumed by the Company. The Company's Board of Directors has delegated the authority for setting market risk limits to a Risk Management Committee. 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 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 weighted average cost of gas calculation. Equity price risk - Investments in telecommunications companies' equity securities are carried at market value or, if market value is not readily determinable, at cost. The Company's investments in such securities totaled $217.1 million at June 30, 2002. A temporary decline in value of ten percent would result in a $21.7 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 $21.7 million reduction in fair value and a corresponding adjustment to net income, net of tax effect. SOUTH CAROLINA ELECTRIC & GAS COMPANY FINANCIAL SECTION PART I. FINANCIAL INFORMATION Item 1. Financial Statements SOUTH CAROLINA ELECTRIC & GAS COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) -------------------------------------------------------------------------------- June 30, December 31, Millions of dollars 2002 2001 -------------------------------------------------------------------------------- Assets Utility Plant: Electric $4,862 $4,563 Gas 432 425 Other 195 188 -------------------------------------------------------------------------------- Total 5,489 5,176 Accumulated depreciation and amortization (1,899) (1,841) -------------------------------------------------------------------------------- Total 3,590 3,335 Construction work in progress 420 511 Nuclear fuel, net of accumulated amortization 50 45 -------------------------------------------------------------------------------- Utility Plant, Net 4,060 3,891 -------------------------------------------------------------------------------- Nonutility Property and Investments, Net 24 24 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- Current Assets: Cash and temporary investments 63 78 Receivables 246 212 Receivables - affiliated companies 3 4 Inventories (at average cost): Fuel 44 39 Materials and supplies 49 48 Emission allowances 13 13 Prepayments 21 6 -------------------------------------------------------------------------------- Total Current Assets 439 400 -------------------------------------------------------------------------------- Deferred Debits: Environmental 21 24 Nuclear plant decommissioning fund 83 79 Pension asset, net 252 239 Due from affiliates - pension and postretirement benefits 16 15 Other regulatory assets 202 193 Other 107 97 -------------------------------------------------------------------------------- Total Deferred Debits 681 647 -------------------------------------------------------------------------------- Total $5,204 $4,962 ================================================================================ SOUTH CAROLINA ELECTRIC & GAS COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) -------------------------------------------------------------- ----------------- June 30, December 31, Millions of dollars 2002 2001 -------------------------------------------------------------- ----------------- Capitalization and Liabilities Stockholders' Investment: Common equity $1,768 $1,750 Preferred stock (Not subject to purchase or sinking funds) 106 106 -------------------------------------------------------------- ----------------- Total Stockholders' Investment 1,874 1,856 Preferred Stock, net (Subject to purchase or sinking funds) 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 50 50 Long-Term Debt, net 1,609 1,412 -------------------------------------------------------------- ----------------- Total Capitalization 3,543 3,328 -------------------------------------------------------------- ----------------- Current Liabilities: Short-term borrowings 213 165 Current portion of long-term debt 25 28 Accounts payable 112 99 Accounts payable - affiliated companies 70 78 Customer deposits 21 19 Taxes accrued 21 80 Interest accrued 33 27 Dividends declared 40 42 Deferred income taxes, net 17 12 Other 9 8 -------------------------------------------------------------- ----------------- Total Current Liabilities 561 558 -------------------------------------------------------------- ----------------- Deferred Credits: Deferred income taxes, net 605 599 Deferred investment tax credits 107 109 Reserve for nuclear plant decommissioning 83 79 Due to affiliates - pension and postretirement benefits 17 16 Postretirement benefits 127 122 Regulatory liabilities 95 81 Other 66 70 -------------------------------------------------------------- ----------------- Total Deferred Credits 1,100 1,076 -------------------------------------------------------------- ----------------- Total $5,204 $4,962 ============================================================== ================= See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) -------------------------------------------------------------------------------- Six Months Ended June 30, Millions of dollars 2002 2001 -------------------------------------------------------------------------------- Cash Flows From Operating Activities: Net income $92 $97 Adjustments to reconcile net income to net cash provided from operating activities: Depreciation and amortization 84 82 Amortization of nuclear fuel 7 6 Allowance for funds used during construction (18) (7) Gain on sale of assets - (1) Over (under) collections, fuel adjustment clauses (11) (11) Changes in certain assets and liabilities: (Increase) decrease in receivables (33) 31 (Increase) decrease in inventories (6) (9) (Increase) decrease pension asset (13) (20) (Increase) decrease other regulatory assets 2 2 Increase (decrease) deferred income taxes, net 11 19 Increase (decrease) other regulatory liabilitie 18 9 Increase (decrease) postretirement benefits 5 4 Increase (decrease) in accounts payable 5 (51) Increase (decrease) in taxes accrued (59) (14) Increase (decrease in interest accrued 6 6 Other, net (25) (32) -------------------------------------------------------------------------------- Net Cash Provided From Operating Activities 65 111 -------------------------------------------------------------------------------- Cash Flows From Investing Activities: Utility property additions and construction expenditures, net of AFC (238) (151) Proceeds from sales of assets 1 1 Nonutility property additions (1) - Investments (3) - -------------------------------------------------------------------------------- Net Cash Used For Investing Activities (241) (150) -------------------------------------------------------------------------------- Cash Flows From Financing Activities: Proceeds: Issuance of First Mortgage Bonds 295 149 Capital contribution from parent 3 15 Repayments: First and Refunding Mortgage Bonds (104) - Other long-term debt (2) (2) Dividends and distributions: Common stock (75) (77) Preferred stock (4) (4) Short-term borrowings, net 48 (72) -------------------------------------------------------------------------------- Net Cash Provided From Financing Activities 161 9 -------------------------------------------------------------------------------- Net Decrease In Cash and Temporary Investments (15) (30) Cash and Temporary Investments, January 1 78 60 -------------------------------------------------------------------------------- Cash and Temporary Investments, June 30 $63 $30 ================================================================================ Supplemental Cash Flow Information: Cash paid for - Interest (net of capitalized interest of $7 for 2002 and $4 for 2001) $84 $77 - Income taxes $45 11 See Notes to Condensed Consolidated Financial Statements. 50 SOUTH CAROLINA ELECTRIC & GAS COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS June 30, 2002 (Unaudited) The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in South Carolina Electric & Gas Company's (the Company) Annual Report on Form 10-K for the year ended December 31, 2001. These are interim financial statements, and due to the seasonality of the Company's business, the amounts reported in the Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the year. In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature which are necessary for a fair statement of the results for the interim periods reported. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. 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, "Accounting for the Effects of Certain Types of Regulation." SFAS 71 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 June 30, 2002 approximately $223 million and $95 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets, and liabilities of approximately $125 million and $86 million, respectively. The electric and gas regulatory assets of approximately $56 million and $41 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 are 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. B. New Accounting Standards SFAS 143, "Accounting for Asset Retirement Obligations," provides guidance for recording and disclosing liabilities related to the future obligation to retire an asset (ARO). The Company will adopt SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on the Company's financial position has not been determined but could be material. Because any ARO anticipated to be recorded would relate to regulated operations, it is not expected that the adoption of the statement will have any impact on results of operations or cash flows. The provisions of SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" became 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. SFAS 145, "Rescission of SFASs 4, 44 and 64, Amendment of SFAS 13, and Technical Corrections," was issued in April 2002. The provisions of SFAS 145, among other things, discontinue treating gains or losses from the early extinguishment of debt as extraordinary items unless such early extinguishment meets the criteria of Accounting Principles Board Opinion No. 30. The Company will adopt SFAS 145 effective January 1, 2003 and does not expect that such adoption will have any impact on the Company's results of operations, cash flows or financial position. SFAS 146 "Accounting for Costs Associated with Exit or Disposal Activities," was issued in July 2002. This statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The Company will adopt SFAS 146 effective January 1, 2003, and does not expect that such adoption will have any impact on the Company's results of operations, cash flows or financial position. C. Reclassifications Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2002. 2. RATE AND OTHER REGULATORY MATTERS Electric In April 2002 the SCPSC approved the Company's request to increase the fuel component of rates charged to electric customers from 1.579 cents per kilowatt-hour to 1.722 cents per kilowatt-hour. The increase reflects higher fuel costs projected for the period May 2002 through April 2003. The increase also provides recovery for under-collected actual fuel costs through April 2002, 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 2002. In September 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 June 30, 2002 no accelerated depreciation has been recorded. The accelerated capital recovery plan will be accomplished through existing customer rates. 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 period January 1, 2001 through June 30, 2002 was as follows: Rate Per Therm Effective Date $.993 January-February 2001 $.793 March-October 2001 $.596 November 2001-June 2002 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 1.1 cents per therm to 3.0 cents per therm, which is intended to provide for the recovery of the balance remaining at June 30, 2002 ($20.6 million) prior to the end of 2005. 3. 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 on March 11, 2002 its First and Refunding Mortgage Bonds, 8 7/8 percent Series due August 15, 2021. 4. 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 June 30, 2002 approximately $39 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock. 5. COMMITMENTS AND CONTINGENCIES Reference is made to Note 12 of Notes to Consolidated Financial Statements appearing in the Company's Annual Report on Form 10-K for the year ended December 31, 2001. Commitments and Contingencies at June 30, 2002 include the following: A. Lake Murray Dam Reinforcement In 1999 the Federal Energy Regulatory Commission (FERC) mandated that the Company reinforce its 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 approximately $250 million and be completed in 2005. 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 V. C. Summer Nuclear Station (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. 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 $15.5 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 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 $20.6 million at June 30, 2002. The deferral includes the estimated costs associated with the following matters. In September 1992 the Environmental Protection Agency (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 late 2002. The Company anticipates that major remediation activities will be completed in 2003, with certain monitoring activities continuing until 2007. As of June 30, 2002, the Company has spent approximately $17.9 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 before 2006. The Company has spent approximately $2.0 million related to these sites and expects to spend an additional $6.0 million. 6. SEGMENT OF BUSINESS INFORMATION The Company's reportable segments are listed in the following table. The Company uses operating income to measure profitability for its reportable segments. Therefore, net income is not allocated to these segments. Affiliate revenue is derived from transactions between reportable segments as well as transactions between separate legal entities that are combined into the same reportable segment. Accumulated depreciation is not assignable to the Company's segments. The Electric Operations segment is comprised of the electric portion of the Company and South Carolina Fuel Company (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. The Gas Distribution segment, comprised of the Company's local distribution operations, 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 Operations' product differs from Gas Distribution's, as does the generation process and method of distribution. Disclosure of Reportable Segments (Millions of Dollars) ------------------------------------- -------------- ---------------- --------- Three months ended External Intersegment Operating Segment June 30, 2002 Revenue Revenue Income (Loss) Assets ------------------------------------- -------------- ---------------- --------- Electric Operations $350 $55 $83 $5,245 Gas Distribution 53 1 (4) 435 All Other - - - 4 Adjustments/Eliminations - (56) - (480) ------------------------------------- -------------- ---------------- --------- ------------------------------------- -------------- ---------------- --------- Consolidated Total $403 - $79 $5,204 ===================================== ============== ================ ========= -------------------------------- --------------- ---------------- ----------- Six months ended External Intersegment Operating Segment June 30, 2002 Revenue Revenue Income (Loss) Assets -------------------------------- --------------- ---------------- ----------- Electric Operations $654 $107 $167 $5,245 Gas Distribution 160 1 12 435 All Other - - - 4 Adjustments/Eliminations - (108) (1) (480) ----------------------------------- --------------- ---------------- ----------- ----------------------------------- --------------- ---------------- ----------- Consolidated Total $814 - $178 $5,204 =================================== =============== ================ =========== ---------------------------------- ------------- ----------------- ----------- Three months ended External Intersegment Operating Segment June 30, 2001 Revenue Revenue Income (Loss) Assets ---------------------------------- ------------- ----------------- ----------- Electric Operations $342 $52 $94 $4,790 Gas Distribution 58 - (5) 423 All Other - - - 5 Adjustments/Eliminations - (52) (1) (457) ----------------------------------- ------------- ----------------- ----------- ----------------------------------- ------------- ----------------- ----------- Consolidated Total $ 400 - $88 $4,761 =================================== ============= ================= =========== --------------------------------- --------------- ---------------- ----------- Six months ended External Intersegment Operating Segment June 30, 2001 Revenue Revenue Income (Loss) Assets --------------------------------- --------------- ---------------- ----------- Electric Operations $683 $99 $184 $4,790 Gas Distribution 215 - 16 423 All Other - - - 5 Adjustments/Eliminations - (99) (2) (457) ---------------------------------- --------------- ---------------- ----------- Consolidated Total $898 - $198 $4,761 ================================== =============== ================ =========== 7. SUBSEQUENT EVENTS A. On August 2, 2002 the Company filed a registration statement with the Securities and Exchange Commission for the proposed issuance and sale of up to 6,000,000 shares of SCANA Common Stock. The offering is expected to be concluded in fall of 2002. Net proceeds from the sale will be contributed to the equity capital of SCE&G or used for general corporate purposes. B. On August 6, 2002 SCE&G filed an application with the SCPSC requesting a $105 million increase in retail electric revenues. The electric rate request is largely associated with the power generation projects at SCE&G's recently completed Urquhart Station and the generating station currently under construction in Jasper County. It also includes costs for equipment required for environmental and air quality improvements. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations ------------------------------------------------------------------------------- SOUTH CAROLINA ELECTRIC & GAS COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in South Carolina Electric & Gas Company's (SCE&G) Annual Report on Form 10-K for the year ended December 31, 2001. Statements included in this discussion and analysis (or elsewhere in this quarterly 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 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. At the Federal level, energy legislation has passed both houses of Congress in 2002, though significant differences exist between the House and Senate versions. Among other things, this legislation would require that one percent of the electric energy sold by retail electric suppliers be generated from renewable energy resources beginning in 2005. This requirement would gradually escalate to ten percent in 2019. Substantial penalties would be levied for failure to comply. Electric cooperatives and municipal utilities would be exempt from these requirements. In addition, on July 31, 2002, FERC proposed new rules aimed at creating a standard market design for wholesale electric markets. See Other Matters-Regional Transmission Organization, in this Management's Discussion and Analysis of Financial Condition and Results of Operations. SCE&G is not able to predict whether these or similar legislative or regulatory actions will be enacted and, if they are, the impact they will have on SCE&G. 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. On August 6, 2002 SCE&G filed an application with the Public Service Commission of South Carolina (SCPSC) requesting a $104.7 million increase in retail electric revenues. The electric rate request is largely associated with the power generation projects at SCE&G's recently completed Urquhart Station and the Jasper Generating Station currently under construction, both of which are discussed below. It also includes costs for equipment required for environmental and air quality improvements. The following table summarizes how SCE&G generated and used funds for property additions and construction expenditures during the six months ended June 30, 2002 and 2001: -------------------------------------------------------------------------------- Six Months Ended June 30, Millions of dollars 2002 2001 ------------------------------------------------------------------- ------------ Net cash provided from operating activities $65 $111 Net cash provided from for financing activities 161 9 Cash and temporary cash investments available at the beginning of the period 78 60 ------------------------------------------------------------------- ------------ Net cash available for utility property additions and construction expenditures $304 $180 =================================================================== ============ Funds used for utility property additions and construction expenditures, net of noncash allowance for funds used during construction $238 $151 =================================================================== ============ SCE&G anticipates that the remainder of its 2002 cash requirements will be met through internally generated funds, the incurrence of additional short-term and long-term indebtedness and a capital contribution from SCANA Corporation. See Note 7A of Notes to Condensed Consolidated Financial Statements. SCE&G expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the next 12 months and for the foreseeable future. SCE&G's ratio of earnings to fixed charges for the 12 months ended June 30, 2002 was 3.54. 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 on March 11, 2002 its First and Refunding Mortgage Bonds, 8 7/8 percent Series due August 15, 2021. SCE&G placed in service a $248 million gas turbine generator project in Aiken County, South Carolina in June 2002. Two combined-cycle turbines burn natural gas to produce 340 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. In 1999 FERC mandated that SCE&G reinforce its 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 approximately $250 million and be completed in 2005. In May 2002 SCE&G began construction of 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. The $450 million facility is expected to begin commercial operation in the summer of 2004, and SCG Pipeline, Inc., an affiliate, will transport natural gas to the facility. 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. SECURITIES RATINGS (As of July 31, 2002) ------------------------------------------------------------------------------- First and First Refunding Trust Rating Mortgage Mortgage Preferred Preferred Commercial Agency Bonds Bonds Stock Securities Paper Moody's A1 A1 Baa1 A3 P-1 Standard & Poor's A- A- BBB BBB A-1 Fitch Ratings A+ A+ A A F-1 ------------------------------------------------------------------------------- These ratings reflect the downgrade issued by Standard & Poor's on July 31, 2002. The Company does not expect the downgrade to adversely impact the Company's liquidity. Environmental Matters For information on environmental matters see Note 5C of Notes To Condensed Consolidated Financial Statements. Other Matters Regional Transmission Organization (RTO) In June 2002 the Company and the other two electric utilities that formed GridSouth Transco LLC (GridSouth) suspended implementation of GridSouth. Though the three companies continue to support the RTO concept, GridSouth implementation was suspended pending the issuance and evaluation of new FERC directives. In July 2002 FERC issued a Notice of Proposed Rulemaking (NOPR) which further defines FERC's new standard market design for wholesale electric markets, including bidding rules and other measures to create a common market framework. The Company is currently evaluating this NOPR to determine what effect it will have on the Company's operations. Additional directives from FERC are expected later in 2002. Transit SCE&G and the City of Columbia, South Carolina (City) have entered into an agreement under which a regional transit authority is expected to take over operation of SCE&G's transit system effective August 31, 2002. As part of the agreement, SCE&G will pay the City $32 million over seven years in exchange for a 30-year electric and gas franchise, will convey transit-related property and equipment to the City and will convey the historic Columbia Canal and Hydroelectric Plant to the City. The transaction has been approved by the SCPSC and the SEC, but is still subject to approval by FERC and other customary conditions to closing. Nuclear Station License Extension In August 2002 SCE&G filed an application with the Nuclear Regulatory Commission (NRC) for a 20-year license extension for its V. C. Summer Nuclear Station (Summer Station). If approved, the extension would allow the plant to operate through 2042. RESULTS OF OPERATIONS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2002 AS COMPARED TO THE CORRESPONDING PERIOD IN 2001 Net Income Net income for the second quarter and year to date periods ended June 30, 2002 and 2001 was as follows: -------------------------------------------------------- ----------------------- Second Quarter Year to Date Millions of dollars 2002 2001 Change 2002 2001 Change ----------------------------- ------- -------------- ------ -------------------- Net income $39.4 $43.0 $(3.6) (8.4%) $91.4 $96.5 $(5.1) (5.3%) ----------------------------- ------- -------------- ------ -------------- ---- Second Quarter 2002 vs 2001 Net income decreased primarily due to higher operation and maintenance expenses and lower pension income, which were partially offset by increased electric margins. Year to Date 2002 vs 2001 Net income decreased primarily due to higher operation and maintenance expenses, lower pension income and lower electric and gas margins in the first quarter, which were partially offset by higher electric margins in the second quarter. Pension Income For the last several years, the market value of the Company's retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. Pension income in the second quarter and the year to date periods of 2002 decreased significantly compared to corresponding periods in 2001 primarily as a result of a less favorable investment market. Pension income during these periods was recorded on the Company's financial statements as follows: -------------------------------------------------------------------------------- Second Quarter Year to Date Millions of dollars 2002 2001 2002 2001 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Financial Statement Impact: Reduction in employee benefit costs $3.1 $4.8 $6.6 $9.6 Increase in other income 1.9 3.0 3.9 6.0 Reduction in capital expenditures 1.0 1.4 1.9 2.8 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Total Pension Income $6.0 $9.2 $12.4 $18.4 =============================================================================== Allowance for Funds Used During Construction (AFC) AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. Both the equity and the debt portions of AFC are noncash items of nonoperating income which have the effect of increasing reported net income. AFC represented approximately 15 percent and 13 percent of income before income taxes for the three and six months ended June 30, 2002, respectively. AFC represented approximately six percent and five percent of income before income taxes and preferred stock dividends for the three and six months ended June 30, 2001. The increase in AFC for the three and six months ended June 30, 2002 compared to the corresponding periods in 2001, is primarily the result of increased construction expenditures related to the projects at Urquhart Station, Jasper County and Lake Murray Dam (see discussion at LIQUIDITY AND CAPITAL RESOURCES). Dividends Declared SCE&G's Board of Directors declared the following dividends on common stock held by SCANA during 2002: -------------------- ------------------ -------------------- ----------------- Declaration Date Dividend Amount Quarter Ended Payment Date -------------------- ------------------ -------------------- ----------------- February 21, 2002 $34.0 million March 31, 2002 April 1, 2002 May 2, 2002 $38.0 million June 30, 2002 July 1, 2002 August 1, 2002 $40.5 million September 30, 2002 October 1, 2002 -------------------- ------------------ -------------------- ----------------- Electric Operations Electric Operations is comprised of the electric portion of SCE&G and South Carolina Fuel Company. Changes in the electric operations sales margins were as follows:

Second Quarter 2002 vs 2001 Margin increased due to more favorable weather. Fuel used in generation increased and purchased power cost decreased due to the repowering project at the Urquhart plant which was completed in June 2002 and higher utilization of steam plants during the planned maintenance outage at Summer Station in 2002. Year to Date 2002 vs 2001 Margin increased due to more favorable weather in the second quarter, which was partially offset by less favorable weather in the first quarter. Fuel used in generation increased and purchased power cost decreased due to more plants being on line during the period. Gas Distribution Gas Distribution is comprised of the local distribution operations of SCE&G. Changes in the gas distribution sales margins were as follows:

Second Quarter 2002 vs 2001 Margin increased primarily due to customer growth. Revenues and gas purchases decreased as a result of lower commodity natural gas prices. Year to Date 2002 vs 2001 Margin decreased primarily due to milder weather and weak economic conditions in the first quarter, which was partially offset by customer growth in the second quarter. Revenues and gas purchases decreased as a result of lower commodity natural gas prices. Other Operating Expenses Changes in other operating expenses were as follows:

Other operating expenses for the three and six months ended June 30, 2002 increased primarily as a result of increased nuclear refueling maintenance costs, reduced pension income in 2002 and higher property insurance costs. The increase in depreciation and amortization expenses for the three months ended June 30, 2002 resulted primarily from normal property additions. Other taxes increased primarily as a result of increased property taxes. Other Income Other income for the six months ended June 30, 2002 increased when compared to the corresponding periods in 2001, primarily as a result of the increase in the equity component of AFC (see AFC discussion at Earnings and Dividends). Income Taxes Income taxes for the three and six months ended June 30, 2002 decreased when compared to the corresponding period in 2001, primarily as a result of the change in operating income. In addition, the equity component of AFC is not taxable; therefore the higher AFC discussed previously did not result in a corresponding increase in income taxes. Item 3. Quantitative and Qualitative Disclosures About Market Risk All financial instruments held by SCE&G and 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.

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. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED FINANCIAL SECTION PART I. FINANCIAL INFORMATION Item 1. Financial Statements. -------------------- PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) ------------------------------------------------------------- ------------------ June 30, December 31, Millions of dollars 2002 2001 ------------------------------------------------------------- ------------------ Assets Gas Utility Plant $874 $855 Accumulated depreciation (302) (288) Acquisition adjustment, net of accumulated amortization 439 439 ------------------------------------------------------------- ------------------ Gas Utility Plant, Net 1,011 1,006 ------------------------------------------------------------- ------------------ Nonutility Property and Investments, Net 28 29 ------------------------------------------------------------- ------------------ Current Assets: Cash and temporary investments 44 18 Restricted cash and temporary investments 2 2 Receivables (net of allowance for uncollectible accounts of $2 for 2002 and $1 for 2001) 23 70 Receivables - affiliated companies 16 12 Inventories (at average cost): Stored gas 33 47 Materials and supplies 9 8 ------------------------------------------------------------- ------------------ Total Current Assets 127 157 ------------------------------------------------------------- ------------------ Deferred Debits: Due from affiliate-pension asset 14 14 Regulatory assets 16 11 Other 5 4 ------------------------------------------------------------- ------------------ Total Deferred Debits 35 29 ------------------------------------------------------------- ------------------ Total $1,201 $1,221 ============================================================= ================== ============================================================= ================== Capitalization and Liabilities Capitalization: Common equity $725 $715 Long-term debt, net 291 290 ------------------------------------------------------------- ------------------ Total Capitalization 1,016 1,005 ------------------------------------------------------------- ------------------ Current Liabilities: Current portion of long-term debt 4 4 Accounts payable 15 41 Accounts payable -affiliated companies 10 10 Customer prepayments and deposits 19 17 Taxes accrued 1 5 Dividends declared and interest accrued 10 6 Other 3 3 ------------------------------------------------------------- ------------------ Total Current Liabilities 62 86 ------------------------------------------------------------- ------------------ Deferred Credits: Deferred income taxes, net 87 86 Deferred investment tax credits 2 2 Due to affiliate-postretirement benefits 15 14 Regulatory liabilities 4 14 Other 15 14 ------------------------------------------------------------- ------------------ Total Deferred Credits 123 130 ------------------------------------------------------------- ------------------ Total $1,201 $1,221 ============================================================= ================== See Notes to Condensed Consolidated Financial Statements. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) -------------------------------------------------------------------------------- Six Months Ended June 30, Millions of dollars 2002 2001 -------------------------------------------------------------------------------- Cash Flows From Operating Activities: Net income $19 $16 Adjustments to reconcile net income to net cash provided from operating activities: Depreciation and amortization 19 22 Excess distributions (undistributed earnings) of investee - 3 Over (under) collection, fuel adjustment clause (15) 14 Changes in certain assets and liabilities: (Increase) decrease in receivables, net 43 90 (Increase) decrease in inventories 13 (6) Increase (decrease) in accounts payable and advances (26) (94) Increase (decrease) in deferred income taxes, net 1 2 Increase (decrease) in accrued taxes (4) (2) Other, net 4 (2) ------------------------------------------------------------------------- ------ Net Cash Provided From Operating Activities 54 43 ------------------------------------------------------------------------- ------ Cash Flows From Investing Activities: Construction expenditures (24) (29) Nonutility and other - 1 ------------------------------------------------------------------------- ------ Net Cash Used For Investing Activities (24) (28) ------------------------------------------------------------------------- ------ Cash Flows From Financing Activities: Issuance of medium-term notes - 148 Repayment of short-term borrowings, net - (125) Capital contributions from parent 1 3 Cash dividends (5) (10) -------------------------------------------------------------------------------- Net Cash Provided From (Used For) Financing Activities (4) 16 -------------------------------------------------------------------------------- Net Increase In Cash and Temporary Investments 26 31 Cash and Temporary Investments, January 1 18 8 -------------------------------------------------------------------------------- Cash and Temporary Investments, June 30 $44 $39 ========================================================================= ====== Supplemental Cash Flow Information: Cash paid for - Interest (net of capitalized interest of $0.5 for 2002 and $0.6 for 2001) $9 $6 - Income taxes 16 15 See Notes to Condensed Consolidated Financial Statements. 53 PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS June 30, 2002 (Unaudited) The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in Public Service Company of North Carolina, Incorporated's (the Company) Annual Report on Form 10-K for the year ended December 31, 2001. These are interim financial statements, and due to the seasonality of the Company's business, the amounts reported in the Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the year. In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature which are necessary for a fair statement of the results for the interim periods reported. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. 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, "Accounting for the Effects of Certain Types of Regulation." SFAS 71 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 June 30, 2002 approximately $16 million and $4 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax liabilities of approximately $0.3 million. The North Carolina Utilities Commission (NCUC) has reviewed and approved most of the items shown as regulatory assets through specific orders. Other items represent costs which are not yet approved for recovery by 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. 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. B. New Accounting Standards The Company adopted SFAS 141, "Business Combinations," and SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002. SFAS 141 requires all acquisitions to be accounted for utilizing the purchase method. The Company considers the amounts categorized by the Federal Energy Regulatory Commission (FERC) as "acquisition adjustments" to be goodwill as defined in SFAS 142 and ceased amortization of such amounts upon the adoption of SFAS 142. This amortization is related to the acquisition adjustment of approximately $466 million carried on the books of the Company. The Company has no other intangible assets subject to amortization as provided in SFAS 142. If the Company had ceased amortization during all periods presented in the condensed consolidated statements of operations, net income (loss) would have been as follows:

SFAS 142 provides a six-month transitional period from the effective date of adoption for the Company to perform an assessment of whether there is an indication that goodwill is impaired. The Company's initial analyses indicated that a write down of the acquisition adjustment associated with PSNC ranging from $200 million to $250 million will be required. The final valuation analysis will be completed by December 31, 2002, and any write-down resulting from the analysis will be recorded as the cumulative effect of a change in accounting principle. SFAS 143, "Accounting for Asset Retirement Obligations," provides guidance for recording and disclosing liabilities related to the future obligation to retire an asset (ARO). The Company will adopt SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on the Company's financial position has not been determined but could be material. Because any ARO anticipated to be recorded would relate to regulated operations, it is not expected that the adoption of the statement will have any impact on results of operations or cash flows. The provisions of SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," became 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. SFAS 145, "Rescission of SFASs 4, 44 and 64, Amendment of SFAS 13, and Technical Corrections," was issued in April 2002. The provisions of SFAS 145, among other things, discontinue treating gains or losses from the early extinguishment of debt as extraordinary items unless such early extinguishment meets the criteria of Accounting Principles Board Opinion No. 30. The Company will adopt SFAS 145 effective January 1, 2003 and does not expect that such adoption will have any impact on the Company's results of operations, cash flows or financial position. SFAS 146 "Accounting for Costs Associated with Exit or Disposal Activities," was issued in July 2002. This statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The Company will adopt SFAS 146 effective January 1, 2003, and does not expect that such adoption will have any impact on the Company's results of operations, cash flows or financial position. C. Reclassifications Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2002. 2. RATE AND OTHER REGULATORY MATTERS 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 period January 1, 2001 through June 30, 2002 was as follows: Rate Per Therm Effective Date $.690 January 2001 $.750 February-March 2001 $.650 April-August 2001 $.500 September-October 2001 $.350 November-December 2001 $.300 January 2002 $.215 February-June 2002 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. In June 2000 the NCUC approved the Company's requests for disbursement of up to $28.4 million from the Company's expansion fund to extend natural gas service to Madison, Jackson and Swain Counties, North Carolina. 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. Construction has begun in Jackson County, and approximately $0.9 million in construction costs have been incurred through June 30, 2002. In December 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 $1million 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 material adverse governmental actions and force majeure events. 3. FINANCIAL INSTRUMENTS 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 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. At June 30, 2002 the fair value of these swaps was $0.9 million. The fair value of these interest rate swaps is reflected within other deferred debits on the balance sheet. The corresponding hedged fair value change of the debt is also recorded on the balance sheet. The receipts or payments related to the interest rate swaps are credited or charged to interest expense as incurred. 4. COMMITMENTS AND CONTINGENCIES 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 the cost to remediate the sites to be 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 June 30, 2002 the Company has recorded a liability and associated regulatory asset of $8.9 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 $1.2 million. Management believes that all costs incurred will be recoverable through gas rates. 5. SEGMENT OF BUSINESS INFORMATION Gas Distribution is the Company's only reportable segment. Gas Distribution uses operating income to measure profitability. Intersegment revenues between Gas Distribution and nonreportable segments were not significant. Disclosure of Reportable Segments (Millions of Dollars) ----------------------------------------------------------------------- Three months ended External Operating Segment June 30, 2002 Revenue Income Assets ----------------------------------------------------------------------- Gas Distribution $49 $1 $1,170 All Other - n/a 28 Adjustments/Eliminations - - 3 ----------------------------------------------------------------------- ----------------------------------------------------------------------- Consolidated Total $49 $1 $1,201 ======================================================================= --------------------------------------------- -------------- ------------------- Six months ended External Operating Segment June 30, 2002 Revenue Income Assets --------------------------------------------- -------------- ------------------- Gas Distribution $183 $40 $1,170 All Other - n/a 28 Adjustments/Eliminations - - 3 --------------------------------------------- -------------- ------------------- Consolidated Total $183 $40 $1,201 ============================================= ============== =================== --------------------------------------------- -------------- ------------------- Three months ende External Operating Segment June 30, 2001 Revenue Loss Assets --------------------------------------------- -------------- ------------------- Gas Distribution $67 $(2) $1,179 All Other - n/a 29 Adjustments/Eliminations - - (26) --------------------------------------------- -------------- ------------------- --------------------------------------------- -------------- ------------------- Consolidated Total $67 $(2) $1,182 ============================================= ============== =================== -------------------------------------------- --------------- ------------------- Six months ended External Operating Segment June 30, 2001 Revenue Income Assets -------------------------------------------- --------------- ------------------- Gas Distribution $295 $37 $1,179 All Other - n/a 29 Adjustments/Eliminations - - (26) -------------------------------------------- --------------- ------------------- Consolidated Total $295 $37 $1,182 ============================================ =============== =================== Item 2. Management's Narrative Analysis of Results of Operations. --------------------------------------------------------- PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS The following discussion should be read in conjunction with Management's Narrative Analysis of Results of Operations appearing in Public Service Company of North Carolina, Incorporated's (PSNC) Annual Report on Form 10-K for the year ended December 31, 2001. Statements included in this narrative analysis (or elsewhere in this quarterly 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 and Dividends Net income for the six months ended June 30, 2002 and 2001 was as follows: Millions of dollars 2002 2001 ------------------------------------------------------------------------------- Net income derived from continuing operations $19.2 $15.6 =============================================================================== The increase in net income from continuing operations reflects the elimination of the amortization of the acquisition adjustment of $6.7 million (see Note 1B of Notes to Condensed Consolidated Financial Statements). The increase was also attributable to an increase in gas sales margin, partially offset by higher operating expenses and reduced other income. The nature of PSNC's business is seasonal. The quarters ending June 30 and September 30 are generally PSNC's least profitable quarters due to decreased demand for natural gas related to lower space heating requirements. PSNC's Board of Directors authorized payment of dividends on common stock held by SCANA as follows: -------------------- ------------------ -------------------- ------------------ Declaration Date Dividend Amount Quarter Ended Payment Date -------------------- ------------------ -------------------- ------------------ -------------------- ------------------ -------------------- ------------------ February 21, 2002 $5.0 million March 31, 2002 April 1, 2002 May 2, 2002 $4.0 million June 30, 2002 July 1, 2002 August 1, 2002 $5.5 million September 30, 2002 October 1, 2002 -------------------- ------------------ -------------------- ------------------ Gas Distribution Gas distribution sales margins for 2002 and 2001 were as follows: Millions of dollars 2002 2001 Change % Change ------------------------------------------- --------------------------------- Operating revenues $183.4 $295.6 $(112.2) (38.0%) Less: Cost of gas 88.7 202.3 (113.6) (56.2%) ------------------------------------------- ------------ Gross margin $94.7 $93.3 $1.4 1.5% =========================================== ================================= Gas distribution sales margin for the six months ended June 30, 2002 increased primarily due to increased residential customer growth and industrial usage. The increase in margin was partially offset by lower other operating revenues and the effects of a $1 million reduction in rates in August 2001 related to the acquisition of PSNC by SCANA. Operation and Maintenance Expenses The $1.6 million increase in operation and maintenance expenses from 2001 is primarily due to higher labor costs. Depreciation Expense Depreciation expense decreased due to the elimination of the amortization of the acquisition adjustment in the amount of $6.7 million (see Note 1B of Notes to Condensed Consolidated Financial Statements). The decrease is partially offset by depreciation expense attributable to additions to plant. Other Income Other income decreased $1.7 million primarily due to reduced interest income. 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. PSNC's ratio of earnings to fixed charges for the 12 months ended June 30, 2002 was 2.5. In December 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 3 of Notes to Condensed Consolidated Financial Statements.) SECURITIES RATINGS (As of July 31, 2002) PSNC --------------------------------------------------- --------------------- -------------- -------------- Rating Senior Commercial Agency Unsecured Paper Moody's A2 P-1 Standard & Poor's A- A-1 Fitch Ratings n/a n/a --------------------- -------------- -------------- These ratings reflect the downgrade issued by Standard & Poor's on July 31, 2002. The Company does not expect the downgrade to adversely impact the Company's liquidity. PART II. OTHER INFORMATION Item 1. Legal Proceedings SCANA Corporation: For information regarding legal proceedings see Notes 4 and 13 of Notes To Consolidated Financial Statements appearing in the Company's Annual Report on Form 10-K for the year ended December 31, 2001, and Note 2 and Note 6 of Notes To Condensed Consolidated Financial Statements appearing in this Quarterly Report on Form 10-Q. South Carolina Electric & Gas Company: For information regarding legal proceedings see Notes 3 and 12 of Notes To Consolidated Financial Statements appearing in South Carolina Electric & Gas Company's Annual Report on Form 10-K for the year ended December 31, 2001, and Note 2 and Note 5 " of Notes To Condensed Consolidated Financial Statements appearing in this Quarterly Report on Form 10-Q. Public Service Company of North Carolina, Incorporated: For information regarding legal proceedings see Notes 5 and 11 of Notes To Consolidated Financial Statements appearing in Public Service Company of North Carolina, Incorporated's Annual Report on Form 10-K for the year ended December 31, 2001, and Note 2 and Note 4 of Notes To Condensed Consolidated Financial Statements appearing in this Quarterly Report on Form 10-Q. Item 2, 3, and 5 are not applicable. Item 4. Submission of Matters to a Vote of Security-Holders (not applicable for South Carolina Electric & Gas Company and Public Service Company of North Carolina, Incorporated) ------------------------------------------------------------------- The Annual Meeting of Shareholders of SCANA Common Stock (No Par Value) was held on May 2, 2002. The following matters were voted upon at the meeting. 1. To elect four (4) Class III Directors for the terms specified in the Proxy Statement. Number of Voting Number of Shares Total Shares Voting Voting to Shares Nominee For Withhold Authority Voted Bill L. Amick 89,418,970 1,355,442 90,774,412 Elaine T. Freeman 89,512,340 1,262,072 90,774,412 D. Maybank Hagood 89,345,310 1,429,102 90,774,412 William B. Timmerman 82,805,416 7,968,996 90,774,412 2. To approve the appointment of Deloitte & Touche as independent accountants for the Corporation. Number of Shares FOR 87,294,054 AGAINST 3,148,042 ABSTAIN 332,316 ------ ------- TOTAL 90,774,412 Percent of FOR votes of those shares actually voting for this proposal: 96.2% Item 6. Exhibits and Reports on Form 8-K A. Exhibits SCANA Corporation, South Carolina Electric & Gas Company and Public Service Company of North Carolina, Incorporated: Exhibits filed with this Quarterly Report on Form 10-Q are listed in the following Exhibit Index. Certain of such exhibits which have heretofore been filed with the Securities and Exchange Commission and which are designated by reference to their exhibit numbers in prior filings are hereby incorporated herein by reference and made a part hereof. B. Reports on Form 8-K during the second quarter 2002 were as follows: SCANA Corporation: None South Carolina Electric & Gas Company: None Public Service Company of North Carolina, Incorporated: None SCANA CORPORATION SIGNATURES Pursuant to the requirements 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. SCANA CORPORATION (Registrant) August 13, 2002 By: s/James E. Swan, IV --------------------------------------- James E. Swan, IV Controller (Principal accounting officer) SOUTH CAROLINA ELECTRIC & GAS COMPANY SIGNATURES Pursuant to the requirements 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. SOUTH CAROLINA ELECTRIC & GAS COMPANY ------------------------------------- (Registrant) August 13, 2002 By: s/James E. Swan, IV ------------------------------------ James E. Swan, IV Controller (Principal accounting officer) PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED SIGNATURES Pursuant to the requirements 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. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED (Registrant) August 13, 2002 By: s/James E. Swan, IV ------------------------------------ James E. Swan, IV Controller (Principal accounting officer) EXHIBIT INDEX Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description 1.01 X Amendment No. 1 to Selling Agency Agreement dated as of July 30, 2002 between SCANA Corporation and each of the Agents named in the Selling Agency Agreement - UBS Warburg LLC; Credit Suisse First Boston Corporation, Banc of America Securities LLC and Wachovia Securities, Inc. , formerly known as First Union Securities, Inc. (Filed herewith) 1.02 X Joinder Agreement dated as of August 7, 2002 between SCANA Corporation and BNY Capital Markets, Inc. (Filed herewith) 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) 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) 3.02 X Articles of Amendment of SCANA, dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. 33-62421) 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) 3.04 X Articles of Amendment of SCE&G dated May 22, 2001 (Filed as Exhibit 3.02 to Registration Statement No. 333-65460) 3.05 X Articles of Correction of SCE&G dated June 1, 2001 (Filed as Exhibit 3.03 to Registration Statement No. 333-65460) 3.06 X Articles of Amendment of SCE&G dated June 14, 2001 (Filed as Exhibit 3.04 to Registration Statement No. 333-65460) 3.07 X Articles of Amendment of SCE&G dated August 30, 2001 (Filed herewith) 3.08 X Articles of Amendment of SCE&G dated March 13, 2002 (Filed herewith) 3.09 X Articles of Amendment of SCE&G dated May 9, 2002 (Filed herewith) 3.10 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) 3.11 X Articles of Amendment of PSNC (formerly New Sub II, Inc.) as adopted on February 10, 2001 (Filed as Exhibit 3.02 to Registration Statement No. 333-45206) 3.12 X Articles of Correction of PSNC dated February 11, 2001 (Filed as Exhibit 3.03 to Registration Statement No. 333-45206) 3.13 X By-Laws of SCANA as revised and amended on December 13, 2001 (Filed as Exhibit 3.01 to Registration Statement No. 333-68266) 3.14 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) 3.15 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) EXHIBIT INDEX Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description 4.01 X Articles of Exchange of South Carolina Electric and Gas Company and SCANA Corporation (Filed as Exhibit 4-A to Post-Effective Amendment No. 1 to Registration Statement No. 2-90438) 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 Statement No. 33-32107) 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) 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 (Filed as Exhibit 2-C to Registration Statement No. 2-26459) 4.05 X X Fifth through Fifty-third Supplemental Indentures to 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 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 December 1, 1980 Exhibit 4-C to Registration No. 33-38580 EXHIBIT INDEX Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description April 1, 1981 Exhibit 4-D to Registration No. 33-49421 June 1, 1981 Exhibit 4-D to Registration No. 2-73321 March 1, 1982 Exhibit 4-D to Registration No. 33-49421 April 15, 1982 Exhibit 4-D to Registration No. 33-49421 May 1, 1982 Exhibit 4-D to Registration No. 33-49421 December 1, 1984 Exhibit 4-D to Registration No. 33-49421 December 1, 1985 Exhibit 4-D to Registration No. 33-49421 June 1, 1986 Exhibit 4-D to Registration No. 33-49421 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 July 15, 1991 Exhibit 4-D to Registration No. 33-49421 August 15, 1991 Exhibit 4-D to Registration No. 33-49421 April 1, 1993 Exhibit 4-E to Registration No. 33-49421 July 1, 1993 Exhibit 4-D to Registration No. 33-57955 May 1, 1999 Exhibit 4.04 to Registration No. 333-86387 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) 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) 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) 4.09 X X Trust Agreement for SCE&G Trust I (Filed as Exhibit 4.03 to Registration Statement No. 333-49960) 4.10 X X Certificate of Trust of SCE&G Trust I (Filed as Exhibit 4.04 to Registration Statement No. 333-49960) 4.11 X X Junior Subordinated Indenture for SCE&G Trust I (Filed as Exhibit 4.05 to Registration Statement No. 333-49960) 4.12 X X Guarantee Agreement for SCE&G Trust I (Filed as Exhibit 4.06 to Registration Statement No. 333-49960) 4.13 X X Amended and Restated Trust Agreement for SCE&G Trust I (Filed as Exhibit 4.07 to Registration Statement No. 333-49960) 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) 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) EXHIBIT INDEX Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description 4.16 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) 4.17 X X Third Supplemental Indenture dated as of February 10, 2001 between PSNC and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.11 to Registration Statement No. 333-45206) 4.18 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) 4.19 X X PSNC $150 million medium-term note issued February 16, 2001 (Filed as Exhibit 4.06 to Registration Statement No. 333-68516) 10.01 X SCANA Executive Deferred Compensation Plan as amended July 1, 2001 (Filed as Exhibit 10.01 to Form 10-Q for the quarter ended September 30, 2001) 10.02 X SCANA Supplemental Executive Retirement Plan as amended July 1, 2001 (Filed as Exhibit 10.02 to Form 10-Q for the quarter ended September 30, 2001) 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) 10.03a X SCANA Supplementary Key Executive Severance Benefits Plan as amended July 1, 2001 (Filed as Exhibit 10.03a to Form 10-Q for the quarter ended September 30, 2001) 10.04 X SCANA Performance Share Plan as amended and restated effective January 1, 1998 (Filed as Exhibit 10 (e) to Registration Statement No. 333-86803) 10.05 X SCANA Long-Term Equity Compensation Plan dated January 2001 filed as Exhibit 4.04 to Registration Statement No. 333-37398) 10.06 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) 10.07 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) 10.08 X SCANA Corporation Director Compensation and Deferral Plan effective January 1, 2001 (Filed as Exhibit 10.05 to Registration Statement No. 333-49960) EXHIBIT INDEX Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description 10.09 X Operating Agreement of Pine Needle LNG Company, LLC dated August 8, 1995 (Filed as Exhibit 10.01 to Registration Statement No. 333-45206) 10.10 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) 10.11 X Amended Operating Agreement of Cardinal Extension Company, LLC dated December 19, 1996 (Filed as Exhibit 10.03 to Registration Statement No. 333-45206) 10.12 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) 10.13 X Form of Severance Agreement between PSNC and its Executive Officers (Filed as Exhibit 10.05 to Registration Statement No. 333-45206) 10.14 X Service Agreement between PSNC and SCANA Services, Inc., effective April 1, 2001(Filed as Exhibit 10.06 to Registration Statement No. 333-45206) 10.15 X Service Agreement between SCE&G and SCANA Services, Inc., effective April 1, 2001 (Filed as Exhibit 10.15 to Form 10-Q for the quarter ended September 30, 2001) 99.1 X Certification of Principal Executive Officer (Filed herewith) 99.2 X Certification of Principal Financial Officer (Filed herewith) 99.3 X Certification of Principal Executive Officer (Filed herewith) 99.4 X Certification of Principal Financial Officer (Filed herewith) 99.5 X Certification of Principal Executive Officer (Filed herewith) 99.6 X Certification of Principal Financial Officer (Filed herewith)

PUBLIC SERVICE CO OF NORTH CAROLINA INC 10-Q