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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

        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. SCANA Corporation Yes ý No o South Carolina Electric & Gas Company Yes ý No o Public Service Company of North Carolina, Incorporated Yes ý No o.

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). SCANA Corporation Yes ý No o South Carolina Electric & Gas Company Yes o No ý Public Service Company of North Carolina, Incorporated Yes o No ý.

        Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

(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).

INDEX

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SCANA CORPORATION
FINANCIAL SECTION

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

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See Notes to Condensed Consolidated Financial Statements.

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SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

See Notes to Condensed Consolidated Financial Statements.

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SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

See Notes to Condensed Consolidated Financial Statements.

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SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

(1)

Accumulated other comprehensive income (loss) totaled $(2.1) million and $5.6 million as of March 31, 2004 and December 31, 2003, respectively.

See Notes to Condensed Consolidated Financial Statements.

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SCANA CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)

        The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in SCANA Corporation's (together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, 2003. 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 certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded as of March 31, 2004, approximately $347 million and $549 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.

        Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.

        Under-(over-) collections—fuel adjustment clauses, net represent amounts under or over-collected from customers pursuant to the fuel adjustment clause (electric customers) or gas cost adjustment clause (gas customers) as approved by the Public Service Commission of South Carolina (SCPSC) or North Carolina Utilities Commission (NCUC) during annual hearings.

        Deferred environmental remediation costs represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by the Company. Costs incurred at sites owned by South Carolina Electric & Gas Company (SCE&G) are being recovered through rates. Such costs, totaling approximately $9.8 million, are expected to be fully recovered by the end of 2009. A portion of the costs incurred at sites owned by PSNC Energy has been recovered

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through rates, and management believes the remaining costs of approximately $6.8 million will be recoverable. Amounts incurred and deferred to date that are not currently being recovered through gas rates at PSNC Energy are approximately $2.4 million.

        Asset retirement obligation—nuclear decommissioning represents the regulatory asset associated with the legal obligation to decommission and dismantle V. C. Summer Nuclear Station (Summer Station) as required by SFAS 143, "Accounting for Asset Retirement Obligations."

        Deferred non-conventional fuel tax benefits, net represent the deferral of partnership losses and other expenses of approximately $44 million, offset by the accumulated deferred income tax credits of approximately $117 million associated with SCE&G's two partnerships involved in converting coal to synthetic fuel. Under a plan approved by the SCPSC, any tax credits generated from non-conventional fuel produced by the partnerships and consumed by SCE&G and ultimately passed through to SCE&G, net of partnership losses and other expenses, have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions.

        The storm damage reserve represents an SCPSC approved reserve account capped at $50 million to be collected through rates over a period of approximately ten years. The accumulated storm damage reserve can be applied to offset actual incremental storm damage costs in excess of $2.5 million in a calendar year.

        Franchise agreements represent costs associated with the 30-year electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. These amounts are not earning a return, but are being amortized through cost of service over approximately 15 years.

        Non-legal asset retirement obligations represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets for which no legal retirement obligation exists.

        The SCPSC and the NCUC (collectively, state commissions) have reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by a state commission. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. However, ultimate recovery is subject to state commission 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, liquidity or financial position in the period the write-off would be recorded.

B.    Equity Compensation Plan

        Under the SCANA Corporation Long-Term Equity Compensation Plan (the Plan), certain employees and non-employee directors may receive incentive and nonqualified stock options and other forms of equity compensation. The Company accounts for this equity-based compensation using the intrinsic value method under APB 25, "Accounting for Stock Issued to Employees," and related interpretations. In addition, the Company has adopted the disclosure provisions of SFAS 123, "Accounting for Stock-Based Compensation" and SFAS 148, "Accounting for Stock-Based Compensation-Transition and Disclosure."

        All options have been granted with exercise prices equal to the fair market value of the Company's stock on the respective grant dates since the Plan's inception; therefore, no compensation expense has been recognized in connection with such grants. If the Company had determined to recognize

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compensation expense for the issuance of options based on the fair value method described in SFAS 123, pro forma net income and earnings per share would have been as presented below:

        No options have been granted since 2002.

C.    Pension and Other Postretirement Benefit Plans

        Components of net periodic benefit income or cost recorded by the Company were as follows:

D.    Earnings Per Share

        Earnings per share amounts have been computed in accordance with SFAS 128, "Earnings Per Share." Under SFAS 128, basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share are computed as net income divided by the weighted average number of shares of common stock outstanding during the period after giving effect to securities considered to be dilutive potential common stock. The Company uses the treasury stock method in determining total dilutive potential common stock.

E.    Affiliated Transactions

        SCE&G holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel. SCE&G had recorded as receivables from these affiliated companies approximately $17.8 million and $13.4 million at March 31, 2004 and December 31, 2003, respectively. SCE&G had recorded as payables to these affiliated companies approximately $15.6 million and $12.2 million at March 31, 2004 and December 31, 2003, respectively.

F.     Reclassifications

        Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2004.

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2.     RATE AND OTHER REGULATORY MATTERS

South Carolina Electric & Gas Company (SCE&G)

Electric

        In January 2003, in conjunction with the approval of a retail rate increase, the SCPSC deferred action on the recovery of certain purchased power costs pending the resolution of the appeal of the SCPSC's May 2002 order. In May 2002 the SCPSC approved SCE&G's request to increase the fuel component of rates charged to electric customers, which reflected higher fuel costs projected for the period May 2002 through April 2003. The increase also provided continued recovery for under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of SCE&G's base load generating plants in winter 2000-2001. The Consumer Advocate of South Carolina (Consumer Advocate) appealed to the South Carolina Circuit Court (Circuit Court) the portion of the SCPSC's order related to the recovery of certain purchased power costs. The Circuit Court ruled that the current fuel clause only provides for the recovery of the fuel costs included in purchased power and not the total cost of the power purchased. The Circuit Court remanded the case to the SCPSC for final disposition. In April 2004 the SCPSC approved a stipulation agreement between the Consumer Advocate and SCE&G whereby SCE&G would be allowed to defer for recovery in a future rate proceeding the portion of the purchased power costs not allowed to be recovered through the fuel clause.

        In April 2004 the SCPSC approved SCE&G's request to increase the fuel component of rates charged to electric customers from 1.678 cents per KWh to 1.821 cents per KWh. The increase reflects higher fuel costs projected for the period May 2004 through April 2005. The increase also provides continued recovery for under-collected actual fuel costs through February 2004. The new rates will be effective as of the first billing cycle in May 2004.

Gas

        SCE&G's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by SCE&G.

        SCE&G's cost of gas component in effect during the period January 1, 2003 through March 31, 2004 was as follows:

        The SCPSC allows SCE&G to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former MGPs. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for SCE&G's gas operations that had previously been recorded in deferred debits. In October 2003, as a result of the annual review, the SCPSC approved SCE&G's request to reduce the billing surcharge from 3.0 cents per therm to 0.8 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2009, of the balance remaining at March 31, 2004 of $9.8 million.

Public Service Company of North Carolina, Incorporated (PSNC Energy)

        PSNC Energy'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. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or

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under-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy's gas purchasing practices annually.

        PSNC Energy's benchmark cost of gas in effect during the period January 1, 2003 through March 31, 2004 was as follows:

        For service rendered on and after March 1, 2004, the NCUC authorized PSNC Energy to implement decrements in its sales and transportation rate schedules to reflect a decrease of approximately $5.7 million in PSNC Energy's annual fixed gas costs as well as the current over-recovery of approximately $16.5 million.

        A state expansion fund, established by the North Carolina General Assembly and funded by refunds from PSNC Energy'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 PSNC Energy's requests for disbursement of up to $28.4 million from PSNC Energy's expansion fund to extend natural gas service to Madison, Jackson and Swain Counties in western North Carolina. PSNC Energy estimates that the cost of this project will be approximately $31 million. The Madison County and Jackson County portions of the project were completed in 2002, and the Swain County portion was completed and placed in service in April 2004. Through March 31, 2004 approximately $29 million had been spent on this project.

        In December 1999 the NCUC issued an order approving the Company's acquisition of PSNC Energy. As specified in the order, PSNC Energy 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.     LONG-TERM DEBT

        On February 11, 2004 South Carolina Generating Company, Inc. (GENCO) issued $100 million of senior secured promissory notes maturing February 1, 2024 and bearing a fixed interest rate of 5.49%. Proceeds from this issuance were used to support GENCO's construction program and to repay intercompany advances borrowed for that purpose.

4.     RETAINED EARNINGS

        The Company's Restated Articles of Incorporation do not limit the dividends that may be paid on its common stock. However, the Restated Articles of Incorporation of SCE&G 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 March 31, 2004 approximately $45.3 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G's common stock.

5.     FINANCIAL INSTRUMENTS

Investments

        Certain of the Company's subsidiaries hold investments in marketable securities, some of which are subject to SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities,"

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mark-to-market accounting and some of which are considered cost basis investments for which determination of fair value historically has been considered impracticable. Equity holdings subject to SFAS 115 are categorized as "available for sale" and are carried at quoted market prices, with any unrealized gains and losses credited or charged to other comprehensive income (loss) within common equity on the Company's balance sheet. Debt securities and preferred stock with significant debt characteristics are categorized as "held to maturity" and are carried at amortized cost. When indicated, and in accordance with its stated accounting policy, the Company performs periodic assessments of whether any decline in the value of these securities to amounts below the Company's cost basis is other than temporary. When other than temporary declines occur, write-downs are recorded through operations, and new (lower) cost bases are established. The Company also holds investments in several partnerships and joint ventures, some of which are accounted for using the equity method.

        At March 31, 2004 SCANA Communications Holdings, Inc. (SCH), a wholly owned, indirect subsidiary of the Company, held investments in the following equity and debt securities.

        Magnolia Holding Company, LLC (Magnolia Holding), holds ownership interests in several Southeastern communications companies.

        ITC^DeltaCom, Inc. (ITC^DeltaCom) is a regional provider of telecommunications services. The common shares of ITC^DeltaCom owned by SCH had a market value of $3.7 million, and the warrants owned have a market value of $2.0 million as of March 31, 2004. The ITC^DeltaCom preferred shares owned by SCH are classified as held to maturity due to their debt features, and their market value is not readily determinable.

        Knology, Inc. (Knology) is a fully integrated provider of video, voice, data and advanced communication services to residential and business customers in the southeastern United States. The common shares of Knology (voting and non-voting) owned by SCH had a market value of $32.6 million as of March 31, 2004.

Derivatives

        The Company follows the guidance required by FAS 133 "Accounting for Derivative Instruments and Hedging Activities," as amended, in accounting for derivatives, including those arising from cash flow hedges related to natural gas. The Company also utilizes swap agreements to manage interest rate risk. These transactions are more fully described in Note 9 to the consolidated financial statements in the Company's 2003 Form 10-K.

        The Company recognized gains of approximately $1.9 million and $5.6 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the three months

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ended March 31, 2004 and 2003, respectively. These amounts were recorded in cost of gas. The Company estimates that most of the March 31, 2004 unrealized gain balance of $3.2 million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in 2004 and 2005 as a decrease to gas cost if market prices remain stable. As of March 31, 2004, all of the Company's cash flow hedges settle by their terms before the end of 2006.

        Option premiums and gains resulting from qualifying fair value hedges during the three months ended March 31, 2004 and 2003 were insignificant and were recorded in cost of gas. As of March 31, 2004 all of the Company's fair value hedges had settled.

        At March 31, 2004 the estimated fair value of the Company's swaps totaled $14.3 million (gain) related to combined notional amounts of $333.1 million.

6.     COMMITMENTS AND CONTINGENCIES

        Reference is made to Note 10 to the consolidated financial statements appearing in the Company's Annual Report on Form 10-K for the year ended December 31, 2003. Commitments and contingencies at March 31, 2004 include the following:

A.    Lake Murray Dam Reinforcement

        In October 1999 the United States Federal Energy Regulatory Commission (FERC) mandated that SCE&G reinforce its Lake Murray Dam in order to comply with new federal safety standards. Construction for the project and related activities, which began in the third quarter of 2001 is expected to cost approximately $275 million and be completed in 2005. Costs incurred through March 31, 2004 totaled approximately $192 million.

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 $10.8 billion. Each reactor licensee is currently liable for up to $100.6 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $10 million of the liability per reactor would be assessed per year. SCE&G's maximum assessment, based on its two-thirds ownership of Summer Station, would be approximately $67.1 million per incident, but not more than $6.7 million per year.

        Congress failed to renew the Price-Anderson Indemnification Act when it expired in 2003. The delayed renewal has no impact on the Company due to the "grandfathered" status of existing licensees that are covered under the expired Act until such time as it is renewed.

        SCE&G currently maintains policies (for itself and on behalf of the South Carolina Public Service Authority) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective 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 $15.8 million.

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        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 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 solely to regulated operations.

South Carolina Electric & Gas Company

        At SCE&G, site assessment and cleanup costs are deferred and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $9.8 million at March 31, 2004. The deferral includes the estimated costs associated with the following matters.

        SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for benzene contamination in the intermediate aquifer on surrounding properties. SCE&G anticipates that the remaining remediation activities will be completed by the end of 2004, with certain monitoring and retreatment activities continuing until 2007. As of March 31, 2004, SCE&G has spent approximately $19.8 million to remediate the Calhoun Park site and expects to spend an additional $2 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 the South Carolina Department of Health and Environmental Control (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 the three owned sites will be completed before 2006. As of March 31, 2004, SCE&G has spent approximately $3.1 million related to these sites, and expects to spend an additional $4.9 million.

Public Service Company of North Carolina, Incorporated

        PSNC Energy is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy's actual remediation 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. PSNC Energy has recorded a liability and associated regulatory asset of $6.8 million, which reflects the estimated remaining liability at March 31, 2004. Amounts incurred and deferred to date that are not currently being recovered through gas rates are approximately $2.4 million. Management believes that all MGP cleanup costs incurred will be recoverable through gas rates.

D.    Claims and Litigation

        In 1999 an unsuccessful bidder for the purchase of certain propane gas assets of SCANA Corporation (SCANA) filed suit against SCANA in Circuit Court, seeking unspecified damages. The

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suit alleges the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. The Company does not believe that the resolution of this issue will have a material impact on its results of operations, cash flows or financial position.

        On August 21, 2003, SCE&G was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and South Carolina Electric & Gas Company, in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. The plaintiffs are seeking damages for the alleged improper use of electric transmission easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to non-utility third parties or telecommunication companies for other than the electric utilities' internal use along the electric transmission line right-of-way constitutes a trespass. The Company is confident of the propriety of its actions and intends to mount a vigorous defense. The Company further believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.

        A complaint was filed on October 22, 2003 against SCE&G by the State of South Carolina alleging that SCE&G violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality's limits. The complaint also alleges that SCE&G failed to obey, observe, or comply with the lawful order of the SCPSC by charging franchise fees to those not residing within a municipality. The complaint seeks restitution to all affected customers and penalties up to $5,000 for each separate violation. SCE&G is confident of the reasonableness of its actions and intends to mount a vigorous defense. The allegations contained in the complaint are the subject of a similar lawsuit that was filed and served on SCE&G, for which a Motion to Dismiss is pending. The allegations are also the subject of a purported class action lawsuit filed on or about December 12, 2003 against Duke Energy Corporation, Progress Energy Services Company and SCE&G. SCE&G believes that the resolution of these actions will not have a material adverse impact on its results of operations, cash flows or financial condition. In addition, SCE&G filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to SCE&G's electric and gas service, to approve SCE&G's efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation which the SCPSC deems just and proper to regulate the franchise fee collection process.

        The Company is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company.

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. Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy which meet SFAS 131 criteria for aggregation.

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Disclosure of Reportable Segments
(Millions of dollars)

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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 (together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, 2003.

        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, including competition from alternate fuels in industrial interruptible markets, (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) performance of the Company's pension plan assets, (11) inflation, (12) changes in environmental regulations, (13) volatility in commodity natural gas markets and (14) the other risks and uncertainties described from time to time in the Company's periodic reports filed with the United States Securities and Exchange Commission. The Company disclaims any obligation to update any forward-looking statements.

Electric Operations

        In April 2004 the joint U.S.-Canada Power System Outage Task Force issued its "Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations" (Blackout Report). The Blackout Report contains 46 recommendations that, if implemented, the Task Force believes would improve reliability of North America's interconnected bulk power system (the grid). Full implementation of the Blackout Report's recommendations would require a number of actions by legislative, regulatory and industry participants. However, the Blackout Report asserts as its single most important recommendation that the U.S. Congress should enact the reliability provisions contained in the Energy Bill, different versions of which passed the House and Senate in 2003 but have stalled in conference committee. Various provisions of the Energy Bill related to electric reliability are being resubmitted as separate legislation (reliability legislation). It is anticipated that any reliability legislation, if passed, would make reliability standards mandatory and enforceable with penalties for non-compliance and would strengthen the role of the U.S. Federal Energy Regulatory Commission (FERC), enabling it to enact regulatory initiatives that would significantly change the country's existing regulatory framework governing transmission, open access and energy markets and would attempt, in large measure, to standardize the national energy market. The Company cannot predict whether Congress will enact reliability legislation or the extent to which the other recommendations contained in the Blackout Report will be implemented. If implemented, such legislation could have a significant

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impact on SCE&G's access to or cost of power for its native load customers and on SCE&G's marketing of power outside of its service territory.

        In addition, the North American Electric Reliability Council (NERC) is expected to proceed with its initiatives to develop, establish and enforce standards for the grid. To that end, NERC is working closely with FERC to implement stronger reliability standards among NERC's voluntary membership. SCE&G, along with other NERC members, is also working closely with NERC in these efforts. Such initiatives would be significantly influenced by any reliability legislation enacted by Congress. If implemented, such initiatives by FERC and NERC could have a significant impact on SCE&G's access to or cost of power for its native load customers and on SCE&G's marketing of power outside its service territory.

Retail Gas Marketing

        In March 2004 SCANA Energy acquired approximately 47,000 retail natural gas customers formerly served by another gas marketer in Georgia. With this transaction, SCANA Energy's total customer base represents about a 30 percent share of the 1.5 million customers in Georgia's natural gas market. SCANA Energy remains the second largest natural gas marketer in the state.

        In March 2004 SCANA Energy's term for serving low-income and high credit risk customers was extended by the GPSC for an additional year (beginning September 1).

        In November 2003 the Georgia Public Service Commission (GPSC) filed a petition with FERC seeking a declaratory order on the assignment of interstate capacity. That petition addressed the question of whether FERC would preempt the GPSC if a plan proposed by SCANA Energy for the assignment of Atlanta Gas Light Company's interstate capacity assets to certificated natural gas marketers was adopted by the GPSC. On April 15, 2004 FERC ruled that it continues to maintain jurisdiction and would preempt the GPSC in any plan dealing with interstate capacity assets. SCANA Energy has operated successfully under the current interstate capacity plan and does not expect that FERC's ruling will have any negative impact on operations.

RESULTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2004
AS COMPARED TO THE CORRESPONDING PERIOD IN 2003

Earnings Per Share

        Reported (GAAP) earnings per share of common stock for the periods ended March 31, 2004 and 2003 were as follows:

        Reported (GAAP) earnings per share increased by $.16 due to improved electric margins of $.15, improved gas margins of $.09, lower interest expense of $.01 and a reduction of preferred dividend requirements of $.01. These factors were partially offset by higher operation and maintenance expenses of $.06, higher property taxes of $.02 and higher depreciation and amortization expense of $.02.

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Pension Income

        Pension income was recorded on the Company's financial statements as follows:

        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 first quarter of 2004 increased compared to the corresponding period in 2003 primarily as a result of a more favorable investment market.

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. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. The increase in AFC for the three months ended March 31, 2004 is primarily due to construction expenditures related to the Jasper County Generating Station Project and the Lake Murray Dam Project (see discussion at CAPITAL PROJECTS).

Dividends Declared

        The Company's Board of Directors has declared the following dividends on common stock during 2004:

Electric Operations

        Electric Operations is comprised of the electric operations of SCE&G, South Carolina Generating Company, Inc. (GENCO) and South Carolina Fuel Company, Inc. (Fuel Company). Electric operations sales margins were as follows:

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        Margin increased primarily due to increased retail electric base rates that went into effect in February 2003, for a total impact of $7.1 million, an additional $3.2 million due to favorable weather, $14.6 million from off-system sales and $2.2 million due to customer growth and consumption.

Gas Distribution

        Gas Distribution is comprised of the local distribution operations of SCE&G and Public Service Company of North Carolina, Incorporated (PSNC Energy). Gas distribution sales margins (including transactions with affiliates) were as follows:

        Margin decreased primarily due to decreased recovery of environmental remediation expenses of $3.2 million (offset in operations and maintenance) and an unfavorable competitive position of natural gas relative to alternate fuels of $1.6 million, partially offset by customer growth and increased consumption of $0.5 million.

Gas Transmission

        Gas Transmission is comprised of the operations of South Carolina Pipeline Corporation (SCPC). Gas transmission sales margins (including transactions with affiliates) were as follows:

        Margin increased primarily due to higher transportation revenue as a result of new customers of $1.8 million, partially offset by an unfavorable competitive position of natural gas relative to alternate fuels of $0.5 million.

Retail Gas Marketing

        Retail Gas Marketing is comprised of SCANA Energy, a division of SCANA Energy Marketing, Inc., which operates in Georgia's natural gas market. Retail Gas Marketing revenues and net income were as follows:

        Operating revenues increased primarily as a result of increased volumes and higher average retail prices. Net income increased primarily due to higher margins of $8.9 million partially offset by increased bad debt expense of $1.2 million.

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Energy Marketing

        Energy Marketing is comprised of the Company's non-regulated marketing operations, excluding SCANA Energy. Energy Marketing operating revenues and net loss were as follows:

        Operating revenues decreased primarily as a result of decreased volumes. Net loss decreased primarily due to improved gas margins of $1.7 million.

Other Operating Expenses

        Other operating expenses were as follows:

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        Other operation and maintenance expenses increased primarily due to increased labor and benefit costs of $5.8 million, increased bad debt expenses of $2.0 million, 2004 winter storm restoration expenses of $2.5 million and increased expense at electric generation plants of $3.4 million, partially offset by decreased recovery of environmental remediation expenses of $3.2 million (offset in gas margin) and increased pension income of $2.1 million. Depreciation and amortization increased due to normal net property changes. Other taxes increased primarily due to increased property taxes.

Other Income (Expense)

        Other income, including AFC, decreased primarily due to reduced other non-operating income partially offset by an increase in AFC due to construction expenditures related to the Jasper County Generating Station Project and the Lake Murray Dam Project.

Income Taxes

        Income taxes increased primarily as a result of changes in operating income.

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. 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 March 31, 2004 was 2.95.

        Cash requirements for the Company's regulated subsidiaries arise primarily from their operational needs, funding their construction programs and payment of dividends to SCANA Corporation. The ability of the regulated subsidiaries to replace existing plant investment, as well as to expand to meet future demand for electricity or gas, will depend on their ability to attract the necessary financial capital on reasonable terms. Regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and these subsidiaries continue their ongoing construction programs, rate increases will be sought. The future financial position and results of operations of the regulated subsidiaries will be affected by their ability to obtain adequate and timely rate and other regulatory relief, if requested.

        The following table summarizes how the Company generated and used funds for property additions and construction expenditures during the three months ended March 31, 2004 and 2003:

        SCE&G intends to file an electric rate case with the SCPSC in the summer of 2004 requesting, among other things, recovery of capital expenditures related to the generating facility in Jasper County, South Carolina. This filing will also include SCE&G's plan to use synthetic fuel tax credits to offset

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construction costs of SCE&G's reinforcement dam at Lake Murray. The SCPSC would be expected to render its decision on the filing within six months of the rate application being filed.

CAPITAL TRANSACTIONS

        On February 11, 2004 GENCO issued $100 million of senior secured promissory notes maturing February 1, 2024 and bearing a fixed interest rate of 5.49%. Proceeds from this issuance were used to support GENCO's construction program and to repay intercompany advances borrowed for that purpose.

        Effective May 1, 2004 shares of SCANA's common stock purchased on behalf of participants in the SCANA Investor Plus Plan, Stock Purchase-Savings Plan and Director Compensation and Deferral Plan are being purchased directly from SCANA rather than on the open market. SCANA estimates that these original issue purchases will result in the issuance of approximately 2 million new shares of common stock and provide approximately $65 million in additional common stock equity on an annual basis. In addition, effective April 29, 2004 SCANA discontinued purchasing outstanding shares of common stock on the open market.

CAPITAL PROJECTS

        Construction of SCE&G's 875 megawatt generation facility in Jasper County, South Carolina has been completed. The facility includes three natural gas combustion-turbine generators and one steam-turbine generator. The $450 million facility began commercial operation in May 2004. Approximately $276 million of the capital expenditures have been included in rate base, and the remainder are expected to be included in the rate case previously discussed.

        In October 1999 FERC mandated that SCE&G reinforce its Lake Murray Dam in order to comply with new federal safety standards. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost approximately $275 million and be completed in 2005. Costs incurred through March 31, 2004 totaled approximately $192 million.

        Construction of SCPC's South System Loop was completed in March 2004 at a cost of approximately $21 million. This pipeline stretches 38.3 miles from SCG Pipeline's connection with SCE&G's Jasper County generation facility to Yemassee in Hampton County, South Carolina, providing a new supply source to SCPC's current system.

ENVIRONMENTAL MATTERS

        For information on environmental matters see Note 6C to condensed consolidated financial statements.

OTHER MATTERS

Nuclear Station

        In April 2004 the Nuclear Regulatory Commission (NRC) approved SCE&G's application for a 20-year license extension for its V. C. Summer Nuclear Station (Summer Station). The extension allows the plant to operate through 2042.

Synthetic Fuel

        SCE&G holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel, the use of which fuel qualifies for federal income tax credits. The aggregate investment in these partnerships as of March 31, 2004 is approximately $3 million, and through March 31, 2004, they have generated and passed through to SCE&G approximately $107 million in such tax credits. At March 31, 2004 SCE&G has recorded on its balance sheet $74 million net deferred

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fuel tax benefits, which include partnership losses, net of tax. In addition, Primesouth, Inc, a non-regulated subsidiary of SCANA, operates a synthetic fuel facility for a third party and receives management fees, royalties and expense reimbursements related to these services. Primesouth does not benefit from any synfuel tax credits.

        Under a plan approved by the SCPSC, any tax credits generated and ultimately passed through to SCE&G from synfuel produced for and consumed by SCE&G, net of partnership losses and other expenses, have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions. See Note 1A to the condensed consolidated financial statements.

        In March 2004 the Company received a "No Change" letter from the Internal Revenue Service (IRS) related to SCE&G's interest in the synthetic fuel partnership S. C. Coaltech No. l L.P. for the tax year 2000. This letter supports the Company's position that the synthetic fuel tax credits have been properly claimed.

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 long-term debt issued by the Company and other 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. For interest rate swaps, the figures shown reflect notional amounts and related maturities. Fair values for debt and swaps represent quoted market prices.

        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.

        At March 31, 2004 the Company held investments in the 13% senior unsecured notes (due 2009) of a telecommunications company, the cost basis of which, including accrued interest, is approximately $51.1 million. As these notes are not broadly traded, determination of their fair value is not practicable.

        Commodity price risk—The following table 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. Fair value represents quoted market prices.

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Expected Maturity:

(a)

Weighted average

        Equity price risk—Investments in telecommunications companies' equity securities (excluding preferred stock with significant debt characteristics) are carried at market value or, if market value is not readily determinable, at cost. The carrying value of the Company's investments in such securities totaled $40.4 million at March 31, 2004. A temporary decline in value of ten percent would result in a $4.0 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 (Loss). An other than temporary decline in value of ten percent would result in a $4.0 million reduction in fair value and a corresponding adjustment to net income, net of tax effect.

Item 4. Controls and Procedures

        As of March 31, 2004 an evaluation was performed under the supervision and with the participation of the Company's management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Company's management, including the CEO and CFO, concluded that as of March 31, 2004 the Company's disclosure controls and procedures were effective. There has been no change in the Company's internal control over financial reporting during the quarter ended March 31, 2004 that has materially affected or is reasonably likely to materially affect the Company's internal control over financial reporting.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY
FINANCIAL SECTION

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Item 1.    Financial Statements

SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)