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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM 10-Q

For the Transition Period from                                to                                 

        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)

Owned 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 totaled $5 million and $6 million as of September 30, 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
September 30, 2004
(Unaudited)

        The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in SCANA Corporation's (SCANA, and 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 September 30, 2004, approximately $376 million and $643 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—electric fuel and gas cost adjustment clauses, net represent amounts under-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 the North Carolina Utilities Commission (NCUC) during annual hearings.

        Deferred purchased power costs—In April 2004 the SCPSC approved a stipulation agreement between the Consumer Advocate and South Carolina Electric & Gas Company (SCE&G) whereby SCE&G was allowed to defer for recovery in a future rate proceeding the portion of the purchased

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power costs not allowed to be recovered through the fuel clause. In its rate application filed on July 1, 2004, SCE&G is seeking to recover these deferred purchased power costs through base rates using a three-year amortization schedule. See also Note 2.

        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 by SCE&G at such sites are being recovered through rates. Such costs, totaling approximately $9.3 million, are expected to be substantially recovered by the end of 2009. A portion of the costs incurred at sites owned by Public Service Company of North Carolina, Incorporated (PSNC Energy) has been recovered through rates, and management believes the remaining costs of approximately $6.6 million will be recoverable. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates at PSNC Energy are approximately $1.2 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 $54 million, offset by the tax benefit of those losses and expenses and accumulated synthetic fuel tax credits of approximately $144 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 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. See also Note 2.

        The storm damage reserve represents an SCPSC approved reserve account for SCE&G 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 incremental storm damage operations and maintenance costs in excess of $2.5 million in a calendar year. For the nine months ended September 30, 2004, approximately $9.4 million had been drawn from this reserve account.

        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 rates 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.

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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."

        Options, all of which were granted prior to 2003, were 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 recognized 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:

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C.    Pension and Other Postretirement Benefit Plans

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

        In May 2004, the FASB issued Staff Position (FSP) No. FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" (FSP No. 106-2), which provides guidance on how companies should account for the impact of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the "Act") on its postretirement health care plans. To encourage employers to continue providing postretirement drug benefits, beginning in 2006 the federal government will provide non-taxable subsidy payments to employers who sponsor prescription drug benefits for retirees that are "actuarially equivalent" to the Medicare benefit. The Company has determined that its postretirement health care plans' prescription drug benefits for participants who retired prior to January 1, 1994 are actuarially equivalent to the benefits to be provided under the Act. The Company has adopted the accounting guidance of FSP No. 106-2 effective July 1, 2004. Recognition of the Act has reduced the Company's postretirement health care and life insurance plans' accumulated postretirement benefit obligation by $3.7 million and expense for the third quarter of 2004 by $0.1 million.

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.

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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 $17.4 million and $13.4 million at September 30, 2004 and December 31, 2003, respectively. SCE&G had recorded as payables to these affiliated companies approximately $16.3 million and $12.2 million at September 30, 2004 and December 31, 2003, respectively.

F.    New Accounting Standards

        At the June 30—July 1, 2004 meeting of the Emerging Issues Task Force (EITF), the EITF reached a consensus on Issue No. 02-14, "Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock." The EITF determined that an investor should apply the equity method of accounting when it has an investment in common stock or an investment that is in-substance common stock, as defined, provided that the investor has the ability to exercise significant influence over the operating and financial policies of the investee. This consensus must be applied in reporting periods beginning after September 15, 2004. The Company will adopt the guidance provided by EITF Issue No. 02-14 in the fourth quarter 2004. The Company does not expect the initial adoption of the guidance to have any impact on the Company's results of operations, cash flows or financial position.

        At the March 2004 and November 2003 EITF meetings, the EITF reached consensus on Issue No. 03-01, "The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments." EITF Issue No. 03-01 requires that certain disclosures be made related to investments that are impaired at the balance sheet date but for which an other-than-temporary impairment has not been recognized. Guidance for evaluating whether an investment is other-than-temporarily impaired is also provided. The impairment guidance is to be applied in reporting periods beginning after June 15, 2004. The disclosure guidance is effective for annual financial statements for fiscal years ending after December 15, 2003. The Company's initial adoption on July 1, 2004 of the guidance had no impact on the Company's results of operations, cash flows or financial position.

G.    Reclassifications

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

2.     RATE AND OTHER REGULATORY MATTERS

South Carolina Electric & Gas Company (SCE&G)

        Electric

        On October 18, 2004 the Company announced that SCE&G had entered into a stipulation and settlement agreement with the Staff of the SCPSC in connection with SCE&G's pending retail electric rate increase application that was filed on July 1, 2004. The settlement agreement is subject to review and approval by the SCPSC. If approved in its entirety, the settlement agreement would result in an overall increase in retail electric revenues of approximately $51.1 million (3.57%) based on an adjusted test year ended March 31, 2004, or about 63% of the $81.2 million (5.66%) overall revenue increase requested in the application. The settlement agreement establishes an allowed return on common equity in a range of 10.4% to 11.4%, with rates to be set based on the midpoint of that range (10.9%). The settlement agreement covers all of the major issues addressed in SCE&G's application, including recovery of construction and operating costs for SCE&G's new Jasper County Electric Generating Station, mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing

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the back-up dam at Lake Murray. Similar settlements have been negotiated with several other intervenors in this rate case. Hearings on this request concluded November 5, 2004, and a rate order is expected by year end. If approved, rates under such an order would go into effect January 1, 2005.

        There can be no assurance that the SCPSC will approve the settlement and stipulation agreement(s), in whole or in part. Further, there can be no assurance as to the level of increase, if any, in retail electric rates arising from these proceedings. Testimony presented in these proceedings covered a range of potential revenue adjustments, from an increase of $81.2 million, as filed by SCE&G, to a reduction of approximately $9 million supported by the Consumer Advocate in the hearing.

        In addition, at the November 2004 hearing the SCPSC will consider whether to allow SCE&G to recover through base rates approximately $25.6 million of purchased power costs. These costs were originally approved for recovery through the fuel clause by the SCPSC in a May 2002 order. 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 these purchased power costs. The Circuit Court ruled that the fuel clause only provided 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 February 2004 the General Assembly of South Carolina clarified the definition of the fuel clause to include the total cost of power purchased. 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 purchased power costs not allowed to be recovered through the fuel clause. SCE&G is seeking recovery of such costs in the current proceedings.

        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 were 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 September 30, 2004 was as follows:

        On October 27, 2004, as part of the annual review of gas costs, the SCPSC approved SCE&G's request to increase the cost of gas component from $.877 per therm to $.904 per therm effective with the first billing cycle in November 2004.

        The SCPSC allows SCE&G to recover, through a billing surcharge to its commercial and residential 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 substantially all of the balance remaining at September 30, 2004 of $9.3 million.

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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 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 September 30, 2004 was as follows:

        On October 1, 2004 the NCUC approved PSNC Energy's request to increase the benchmark cost of gas from $.600 per therm to $.675 per therm for service rendered on and after October 1, 2004.

        On September 30, 2004, in connection with PSNC Energy's 2004 Annual Prudence Review, the NCUC determined that PSNC Energy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12-month review period ended March 31, 2004.

        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. The final phase of this project was completed and placed in service in April 2004 at a total cost of approximately $30.2 million.

        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 increases 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.     DEBT AND CREDIT FACILITIES

        In February 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.

        In May 2004 SCE&G borrowed $23.6 million under an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the Lake Murray Dam remediation project. The loan agreement provides for interest-free borrowings for costs incurred not to exceed $59 million with such borrowings being repaid over ten years from the initial borrowing. At September 30, 2004 SCE&G had $22.1 million

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outstanding under the agreement. On October 22, 2004 SCE&G borrowed an additional $11.8 million under the agreement.

        In June 2004 the Company entered into new five-year revolving committed credit facilities totaling $650 million. These new revolving credit facilities replaced $600 million of existing committed credit facilities. SCANA, SCE&G (including South Carolina Fuel Company, Inc.) and PSNC Energy had available the following revolving credit facilities which were unused at September 30, 2004:

⁽¹⁾

Includes $113 million that either SCANA or SCE&G may use.

        On July 15, 2004 SCE&G retired at maturity $100 million of first mortgage bonds. These bonds were bearing interest at 7.70%.

        On October 19, 2004 SCANA retired at maturity $50 million of medium-term notes. These notes were bearing interest at 7.44%.

4.     RETAINED EARNINGS

        SCANA Corporation'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 September 30, 2004 approximately $47 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 SCANA Corporation's subsidiaries hold investments in marketable securities, some of which are subject to SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," 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. Among the factors considered in these assessments is whether an investment's decline in value to below cost basis has continued for greater than six to nine months. 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.

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        At September 30, 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 $2.5 million, and the warrants owned had a market value of $0.8 million as of September 30, 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. In September 2004, and in accordance with the accounting policy described earlier, SCH recorded impairment losses associated with its Knology common stock investment totaling $15.0 million, net of taxes. The common shares of Knology (voting and non-voting) owned by SCH had a market value of $19.7 million as of September 30, 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 $0.3 million and $3.3 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the three and nine months ended September 30, 2004. The Company recognized gains (losses) of approximately $(0.4) million and $5.4 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the three and nine months ended September 30, 2003. These amounts were recorded in cost of gas. The Company estimates that most of the September 30, 2004 unrealized gain balance of $5.6 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 at current

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levels. As of September 30, 2004, all of the Company's cash flow hedges will settle by their terms before the end of 2006.

        Option premiums and gains resulting from qualifying fair value hedges during the three and nine months ended September 30, 2004 and 2003 were insignificant and were recorded in cost of gas. As of September 30, 2004 all of the Company's fair value hedges will settle by February 2005.

        At September 30, 2004 the estimated fair value of the Company's swaps totaled $6.7 million (gain) related to combined notional amounts of $329.9 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 September 30, 2004 include the following:

A.    Lake Murray Dam Reinforcement

        In 2001 SCE&G began construction to reinforce its Lake Murray Dam in order to comply with new federal safety standards mandated by the United States Federal Energy Regulatory Commission (FERC). Construction for the project and related activities is expected to cost approximately $275 million and be completed in 2005. Costs incurred through September 30, 2004 totaled approximately $223 million.

B.    Nuclear Insurance

        The Price-Anderson Indemnification Act 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.

        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. However, 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

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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 are being recovered through rates (see Note 2). Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $9.3 million at September 30, 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 contamination. 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 September 30, 2004, SCE&G had spent approximately $20.2 million to remediate the Calhoun Park site and expects to spend an additional $1.6 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 sites will be completed before 2006. As of September 30, 2004, SCE&G had spent approximately $3.3 million related to these sites, and expects to spend an additional $4.7 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 approximately $6.6 million, which reflects the estimated remaining liability at September 30, 2004. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates are approximately $1.2 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 the Company filed suit against SCANA in Circuit Court, seeking unspecified damages. The suit alleges the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. On October 20, 2004, testimony from all parties was concluded in Circuit Court and the case was sent to the jury. On October 21, 2004, the jury issued its verdict on this matter against the Company for four causes of action for damages totaling $48 million. Post-verdict motions are scheduled to be heard the week of November 15, 2004. It is the Company's interpretation that the damages awarded with respect to certain causes of action are overlapping. Therefore, it is the Company's belief that a reasonably possible estimate of the total damages based on the amounts awarded by the jury will be in the range of $18—$36 million. However, the Company believes that the verdict was inconsistent with the facts presented and applicable law and intends to appeal any adverse judgment by the Circuit Court. Based on the current status of this matter, and in accordance with generally accepted accounting principles, the Company recorded a pre-tax charge to earnings in the third quarter of 2004 of

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$18 million, $11 million after-tax, or 10 cents per share, which is the Company's reasonable estimate of the loss that is probable if the final judgment is consistent with the jury verdict. The charge and associated liability are reported in Other Income (Expense) and Current Liabilities-Other in the financial statements.

        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 SCE&G 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 and distribution 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 and distribution line rights-of-way constitutes a trespass. The Company is confident of the propriety of SCE&G's 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.

        On May 17, 2004, the Company was served with a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation. The case was filed in South Carolina's Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges the Company made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication apparatuses to transmit communications other than the Company's electricity-related internal communications. The plaintiff asserts causes of action for unjust enrichment, trespass, injunction and declaratory judgment. The plaintiff did not assert a specific dollar amount for the claims. The Company believes its actions are consistent with governing law and the applicable documents granting easements and rights-of-way. The Company intends to mount a vigorous defense and 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 alleged 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 sought restitution to all affected customers and penalties up to $5,000 for each separate violation. The State of South Carolina v. SCE&G has been settled by an agreement between the parties, and the settlement has been approved by the court. The allegations contained in the complaint were also the subject of a similar lawsuit that was filed and served on SCE&G but has now been dismissed. 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 (styled Edwards v. SCE&G). Duke Energy and Progress Energy have been voluntarily dismissed from the Edwards lawsuit. The Company 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 that the SCPSC deems just and proper to regulate the franchise fee collection process.

        In addition to other environmental costs being recovered through billing surcharges, as of September 30, 2004, SCE&G is party to certain claims for costs and damages arising from the prior operation of a manufactured gas plant in the Calhoun Park area of Charleston, South Carolina, for

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which claims the National Park Service of the Department of the Interior has demanded payment of approximately $9 million. Any cost arising from the ultimate settlement of these matters is also expected to be recoverable through rates under South Carolina regulatory processes.

        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 (SCANA, and 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) regulatory actions or changes in the utility and nonutility regulatory environment, (3) current and future litigation, (4) changes in the economy, especially in areas served by the Company's subsidiaries, (5) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (6) growth opportunities for the Company's regulated and diversified subsidiaries, (7) the results of financing efforts, (8) changes in the Company's accounting policies, (9) weather conditions, especially in areas served by the Company's subsidiaries, (10) performance of and marketability of the Company's investments in telecommunications companies, (11) performance of the Company's pension plan assets, (12) inflation, (13) changes in environmental regulations, (14) volatility in commodity natural gas markets and (15) 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 certain legislative measures (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 could change, perhaps significantly, 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 and attempt to disaggregate the remaining vertically integrated utilities.

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

Gas Transmission

        In June 2004 the Company announced plans to merge its two natural gas pipeline subsidiaries into one company. Under the plan, South Carolina Pipeline Corporation (SCPC), the Company's intrastate pipeline company, would merge with SCG Pipeline, Inc., the Company's interstate pipeline. The merged companies would operate as a single interstate pipeline company under FERC jurisdiction and would provide transportation services. If approved by FERC, the merger is expected to be completed in 2005.

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 Georgia Public Service Commission (GPSC) for an additional year (through August 31, 2005).

        In November 2003 the 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 filed a motion for reconsideration with FERC, which motion is still pending. 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 AND NINE MONTHS ENDED SEPTEMBER 30, 2004
AS COMPARED TO THE CORRESPONDING PERIODS IN 2003

        The following discussion of the results of operations of the Company includes a non-GAAP measure, GAAP-adjusted net earnings per share from operations, which excludes from net income the effects of sales of, and impairment charges related to, certain investments and the effects of a charge related to pending litigation. Management believes GAAP-adjusted net earnings per share from operations provides a meaningful representation of the Company's fundamental earnings power and can aid in analysis of period-over-period financial performance.

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Earnings Per Share

        Earnings per share of common stock for the periods ended September 30, 2004 and 2003 were as follows: