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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 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)

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 (loss) totaled $3.6 million and $(3.8) million as of March 31, 2005 and December 31, 2004, respectively.

See Notes to Condensed Consolidated Financial Statements.

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SCANA CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(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, 2004. 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, as of March 31, 2005 the Company has recorded approximately $388 million and $587 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- 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 the North Carolina Utilities Commission (NCUC) during annual hearings.

        Deferred purchased power costs—represents costs that were necessitated by outages at two of South Carolina Electric & Gas Company (SCE&G)'s base load generating plants in winter 2000-2001. The SCPSC approved recovery of these costs in base rates over three years beginning January 2005.

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        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 SCE&G are being recovered through rates. Such costs, totaling approximately $9.5 million, are expected to be fully 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 $6.4 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 $1.5 million.

        Asset retirement obligation (ARO)—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."

        Other 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.

        Deferred synthetic fuel tax benefits represented the deferral of partnership losses and other expenses offset by the tax benefits of those losses and expenses and accumulated synthetic fuel tax credits associated with SCE&G's investment in two partnerships involved in converting coal to synthetic fuel. In 2005, under an accounting plan approved by the SCPSC, any tax credits generated from synthetic 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 used to offset the capital costs of constructing the back-up dam at Lake Murray. See Note 2.

        The storm damage reserve represents an SCPSC approved reserve account for SCE&G capped at $50 million to be collected through rates. The accumulated storm damage reserve can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. For the three months ended March 31, 2005, no amounts were 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 over approximately 15 years.

        Deferred regional transmission organization costs represent costs incurred by SCE&G in the United States Federal Energy Regulatory Commission (FERC)-mandated formation of GridSouth. The project was suspended in 2002. These amounts are not earning a return, but are being amortized through cost of service rates over approximately five years beginning in January 2005.

        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

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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 follows:

        The Company also grants other forms of equity based compensation to certain employees. The value of such awards is recognized as compensation expense under APB 25. Total expense recorded for these awards was approximately $1.9 million and $2.3 million for the three months ended March 31, 2005 and 2004, respectively.

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 by dividing net income 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. The Company has no securities that would have an antidilutive effect on earnings per share.

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E.

Affiliated Transactions

        SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel. SCE&G had recorded as receivables from these affiliated companies approximately $16.7 million and $18.6 million at March 31, 2005 and December 31, 2004, respectively. SCE&G had recorded as payables to these affiliated companies approximately $17.2 million and $17.8 million at March 31, 2005 and December 31, 2004, respectively. SCE&G purchased approximately $50.9 million and $38.7 million of synthetic fuel from these affiliated companies for the three months ended March 31, 2005 and 2004, respectively.

F.

New Accounting Matters

        Financial Accounting Standards Board Interpretation (FIN) 47, "Accounting for Conditional Asset Retirement Obligations," was issued in March 2005 to clarify the term "conditional asset retirement" as used in SFAS 143, "Accounting for Asset Retirement Obligations." It requires that a liability be recognized for the fair value of a conditional asset retirement obligation when incurred, if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation would be factored into the measurement of the liability when sufficient information exists. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Accordingly, the Company will adopt FIN 47 in the fourth quarter of 2005. The impact FIN 47 may have on the Company's financial position has not been determined but could be material. The Company does not expect that the initial adoption of FIN 47 will have a material impact on the Company's results of operations or cash flows.

        SFAS 123 (revised 2004), "Share-Based Payment," was issued in December 2004 and will require compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the instruments issued. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) replaces SFAS 123, "Accounting for Stock-Based Compensation" and supersedes APB 25, "Accounting for Stock Issued to Employees." In April 2005, the Securities and Exchange Commission delayed the date for mandatory adoption of SFAS 123(R) until the first interim or annual reporting period of the first fiscal year beginning on or after June 15, 2005. Accordingly, the Company will adopt SFAS 123(R) in the first quarter of 2006. The Company does not expect that the initial adoption of SFAS 123(R) will have a material 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 2005.

2. RATE AND OTHER REGULATORY MATTERS

South Carolina Electric & Gas Company (SCE&G)

Electric

        In a January 2005 order, the SCPSC granted SCE&G a composite increase in retail electric rates of approximately 2.89%, designed to produce additional annual revenues of approximately $41.4 million based on a test year calculation. The SCPSC lowered SCE&G's return on common equity from 12.45% to an amount not to exceed 11.4%, with rates set at 10.7%. The new rates became effective in January 2005. As part of its order, the SCPSC approved SCE&G's recovery of construction and operating costs for SCE&G's new Jasper County Electric Generating Station, recovery of costs of mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and,

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beginning in January 2005, the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray. Under the accounting methodology approved by the SCPSC, current and future construction costs related to the Lake Murray Dam project are recorded in a special dam remediation account outside of rate base, and depreciation will be recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

        In the January 2005 order the SCPSC also approved recovery over a five-year period of SCE&G's approximately $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization and recovery through base rates over three years of approximately $25.6 million of purchased power costs that were previously deferred. As a part of its order, the SCPSC extended through 2010 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.

        In January 2003 the SCPSC granted SCE&G a composite increase in retail electric rates of approximately 5.8% designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The rates and authorized return were effective for service rendered on and after February 1, 2003 until January 2005.

        SCE&G's rates are established using a cost of fuel component approved by the SCPSC which may be modified periodically to reflect changes in the price of fuel purchased by SCE&G. SCE&G's cost of fuel component in effect during the period January 1, 2004 through March 31, 2005 was as follows:

        On April 6, 2005 as part of the annual review of fuel costs, the SCPSC approved SCE&G's request to increase the cost of fuel component from $.01764 per KWh to $.02256 per KWh effective the first billing cycle in May 2005.

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, 2004 through March 31, 2005 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. The billing surcharge is 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, 2005 of $9.5 million.

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        On April 26, 2005, SCE&G filed an application with the SCPSC requesting a 7.09 percent increase in retail natural gas base rates, or approximately $28 million based on an adjusted test year ended December 31, 2004. A hearing on this request is expected to be held and an order is expected to be issued in the fall of 2005. If approved, the new rates would go into effect in November 2005.

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, 2004 through March 31, 2005 was as follows:

        On January 21, 2005 the NCUC authorized PSNC Energy to defer for subsequent rate consideration certain expenses incurred to comply with the U. S. Department of Transportation's Pipeline Integrity Management requirements. This accounting treatment was effective November 1, 2004. As of March 31, 2005 such deferrals were not significant.

        In December 1999 the NCUC issued an order approving SCANA's acquisition of PSNC Energy. As specified in the order, PSNC Energy agreed to a moratorium on general rate increases until after 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 March 2005 SCANA issued $100 million in senior unsecured floating rate medium-term notes maturing in March 2008. The interest rate on the floating rate notes is reset quarterly based on three-month LIBOR plus 15 basis points. The proceeds from the sale, together with available cash, were used for the redemption on April 1, 2005 of $200 million of floating rate medium-term notes due to mature in November 2006.

        In March 2005 SCE&G issued $100 million first mortgage bonds having an annual interest rate of 5.25% and maturing March 1, 2035. The proceeds from the sale of these bonds were used for the redemption on April 1, 2005 of first mortgage bonds, 7.625% Series due April 1, 2025.

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, which the Company considers to be remote, 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, 2005 approximately $49 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G's common stock.

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5. FINANCIAL INSTRUMENTS

        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 SCANA's Annual Report on Form 10-K for the year ended December 31, 2004.

        The Company recognized gains (losses) of approximately $(3) million and $2 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the three months ended March 31, 2005 and 2004, respectively. These amounts were recorded in cost of gas. The Company estimates that most of the March 31, 2005 unrealized gain balance of $4 million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in 2005 as a decrease to gas cost if market prices remain at current levels. As of March 31, 2005, all of the Company's cash flow hedges settle by their terms before the end of 2006.

        At March 31, 2005 the estimated fair value of the Company's swaps totaled $2.2 million (gain) related to combined notional amounts of $275.6 million.

6. COMMITMENTS AND CONTINGENCIES

        Reference is made to Note 10 to the consolidated financial statements appearing in SCANA's Annual Report on Form 10-K for the year ended December 31, 2004. Commitments and contingencies at March 31, 2005 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 (excluding allowance for funds used during construction (AFC)) and be completed in the second quarter of 2005. Costs incurred through March 31, 2005 totaled approximately $251 million.

B.

Nuclear Insurance

        The Price-Anderson Indemnification Act (the Act) deals with public liability for a nuclear incident. Though the Act expired in 2003, existing licensees, such as the Company, are "grandfathered" under the Act until such time as it is renewed. The Act establishes the liability limit for third party claims associated with any nuclear incident at $10.5 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.

        SCE&G currently maintains policies (for itself and on behalf of the South Carolina Public Service Authority, the one-third owner of Summer Station) 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

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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 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 $9.5 million at March 31, 2005. 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 2005, with certain monitoring and retreatment activities continuing until 2010. As of March 31, 2005, SCE&G had spent approximately $20.7 million to remediate the Calhoun Park site and expects to spend an additional $1.1 million. In addition, the National Park Service of the Department of the Interior made an initial demand for payment of approximately $9 million to SCE&G for certain costs and damages relating to this site. Any costs arising from these matters are expected to be recoverable through rates under South Carolina regulatory process.

        SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. One of the sites has been remediated and will undergo routine monitoring until released by the South Carolina Department of Health and Environmental Control (DHEC). The other sites are currently being investigated under work plans approved by DHEC. SCE&G anticipates that major remediation activities for the three sites will be completed in 2010. As of March 31, 2005, SCE&G had spent approximately $4.1 million related to these three sites, and expects to spend an additional $3.9 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 approximately $6.4 million, which reflects the estimated remaining liability at March 31, 2005. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates are approximately $1.5 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 alleged the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. On October 21, 2004, the jury issued an adverse verdict on this matter against SCANA for four causes

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of action for damages totaling $48 million. Post-verdict motions were heard in November 2004 and January 2005. In April 2005, post-trial motions were decided by the Court, and the plaintiff has been ordered to elect a single remedy from the multiple jury awards.

        Upon receiving the jury verdict prior to reporting results for the third quarter of 2004, it was the Company's interpretation that the damages awarded with respect to certain causes of action were overlapping and that the plaintiff would be required to elect a single remedy. Therefore, it was the Company's belief that a reasonably possible estimate of the total damages based on the amounts awarded by the jury would be in the range of $18-$36 million. As such, in accordance with generally accepted accounting principles, in the third quarter of 2004 SCANA accrued a liability of $18 million pre-tax, which was its reasonable estimate of the minimum liability that was probable if the final judgment were to be consistent with the jury verdict.

        In light of the recent election order which is consistent with the interpretation above, the Company believes its accrued liability is still reasonable. However, the Company continues to believe that the verdict was inconsistent with the facts presented and applicable law and intends to appeal any adverse judgment ultimately entered by the Circuit Court.

        The Company is also defending another claim for $2.7 million for reimbursement of legal fees and expenses under an indemnification and hold harmless agreement in the contract of sale. A bench trial on the indemnification was held on January 14, 2005. A ruling has not yet been received, but is expected during the second quarter of 2005.

        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 equipment 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

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agreement between the parties, and the settlement has been approved by the court. The allegations were also the subject of a purported class action lawsuit filed in December 2003, against Duke Energy Corporation, Progress Energy Services Company and SCE&G (styled as Edwards v. SCE&G), but that case has been dismissed by the Plaintiff. 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. The Company believes that the resolution of these matters will not have a material adverse impact on its results of operations, cash flows or financial condition.

        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. All Other includes equity method investments and other nonreportable segments.

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, 2004.

        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 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 subsidiaries of SCANA, (5) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (6) growth opportunities for SCANA'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 SCANA's subsidiaries, (10) performance of SCANA'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 SCANA's periodic reports filed with the United States Securities and Exchange Commission. SCANA disclaims any obligation to update any forward-looking statements.

Electric Operations

        On April 21, 2005, the U. S. House of Representatives passed the Energy Policy Act of 2005 (Energy Policy Act). Some key provisions of the Energy Policy Act that might impact the Company include the establishment of an electric reliability organization to enforce reliability standards for transmission systems, the restriction of standard market design (SMD) rulemaking by the Federal Energy Regulatory Commission (FERC) until 2006 and the provision for continued reservation of electric transmission capacity needed to serve native load customers. The Energy Policy Act also would repeal the Public Utility Holding Company Act of 1935, and would provide for greater regulatory oversight by other federal and state authorities. The U. S. Senate is expected to begin debate on separate energy legislation in May 2005. Differences between such legislation, if passed, and the Energy Policy Act would have to be reconciled, approved by both the House and Senate, and signed by the President before becoming law. The Company cannot predict whether the Energy Policy Act or similar legislation ultimately will be enacted, and if it is, the conditions the final legislation would impose on utilities.

Gas Distribution

        On April 26, 2005, SCE&G filed an application with the Public Service Commission of South Carolina (SCPSC) requesting a 7.09 percent increase in retail natural gas base rates, or approximately $28 million based on an adjusted test year ended December 31, 2004. A hearing on this request is

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expected to be held and an order is expected to be issued in the fall of 2005. If approved, the new rates would go into effect in November 2005.

        In February 2005, the Natural Gas Stabilization Act of 2005 (Stabilization Act) became law in South Carolina. The Stabilization Act allows natural gas distribution companies to request annual adjustments to rates to reflect changes in revenues and expenses and changes in investment. Such annual adjustments are subject to certain qualifying criteria and review by the SCPSC.

Gas Transmission

        In 2005, an application to merge two SCANA subsidiaries, South Carolina Pipeline Corporation and SCG Pipeline, Inc., is expected to be filed with FERC. The merger, which is subject to FERC approval, is expected to be complete in 2005 or 2006.

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RESULTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2005
AS COMPARED TO THE CORRESPONDING PERIOD IN 2004

Earnings Per Share

        Earnings per share of common stock were as follows:

        Earnings per share decreased primarily due to increased depreciation and amortization expense of $.07 (net of income tax benefits applied based on the January 2005 SCPSC order described below), increased operations and maintenance expenses of $.02, increased interest expense of $.02 and the effects of dilution of $.02, was partially offset by favorable electric margins of $.05 and favorable gas margins of $.06. Accelerated depreciation on the Lake Murray back-up dam and recognition of synthetic fuel tax credits and other items had no effect on net income, as discussed below.

Recognition of Synthetic Fuel Tax Credits

        SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel, the use of which fuel qualifies for federal income tax credits. These synthetic fuel production facilities were placed in operation in 2000 and 2001. Under an accounting plan approved by the SCPSC in June 2000, the synthetic fuel tax credits generated by the partnerships and passed through to SCE&G, net of partnership losses and other expenses, were to be deferred until the SCPSC approved their application to offset capital costs of projects required to comply with legislative or regulatory actions.

        In a January 2005 order, the SCPSC approved SCE&G's request to apply these synthetic fuel tax credits to offset the construction costs of the Lake Murray Dam project beginning in January 2005. Under the accounting methodology approved by the SCPSC, current and future construction costs related to the project are recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation will be recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

        The level of depreciation expense and related tax benefit recognized in the income statement will be equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of taxes. As a result, the balance of unrecovered costs in the dam remediation account will decline as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, they can have a significant impact on individual line items within the income statement.

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The accelerated depreciation, synthetic fuel tax credits, partnership losses and the income tax benefit arising from such losses recognized by SCE&G during the first quarter of 2005 are as follows:

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 for the first quarter of 2005 increased compared to the corresponding period in 2004 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. AFC for the three months ended March 31, 2005 decreased slightly primarily due to completion of the Jasper County Electric Generating Station in May 2004. Included in the equity portion of AFC is approximately $2.8 million, which was accrued as a result of the January 2005 SCPSC rate order related to construction costs for the back-up dam at Lake Murray.

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Dividends Declared

        The Company's Board of Directors has declared the following dividends on common stock during 2005:

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:

        Margin increased primarily due to increased retail electric rates that went into effect in January 2005 for a total impact of $14.4 million and customer growth and increase consumption of $1.8 million, which was partially offset by $5.4 million due to unfavorable weather and by $1.1 million related to decreased off-system sales.

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 increased primarily due to customer growth and increased consumption.

Gas Transmission

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

        Margin increased slightly due to higher transportation volumes.

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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 higher average retail prices due to higher commodity gas costs. Net income increased primarily due to customer growth and increased consumption.

Energy Marketing

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

*

Not meaningful

        Operating revenues increased primarily as a result of higher commodity prices which offset decreased volumes. Net income decreased primarily due to lower gas margins.

Other Operating Expenses

        Other operating expenses, which arose from the operating segments previously discussed, were as follows:

*

not meaningful

        Other operation and maintenance expenses increased due to other operating costs (primarily bad debt of $2.7 million) related to increased customers in the Retail Gas Marketing segment, and due to nuclear and fossil maintenance expenses of $4.6 million, offset by decreases in winter storm expenses of $2.5 million and employee benefit expenses. Depreciation and amortization increased approximately $169.7 million due to accelerated depreciation of the back-up dam at Lake Murray (previously discussed at Recognition of Synthetic Fuel Tax Credits) and increased $6.0 million due to the completion of the Jasper County Electric Generating Station in May 2004 and $3.7 million due to normal net property changes.

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Income Taxes

        Income tax expense for the quarter ended March 31, 2005 decreased by approximately $233.2 million as previously discussed at Recognition of Synthetic Fuel Tax Credits.

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, 2005 was 1.91.

        Cash requirements for the Company's regulated subsidiaries arise primarily from their operational needs, funding their construction programs and payment of dividends to SCANA. The ability of the regulated subsidiaries to replace existing plant investment, as well as to expand to meet future demand for electricity and 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.

        In a January 2005 order, the SCPSC granted SCE&G a composite increase in retail electric rates of approximately 2.89%, designed to produce additional annual revenues of approximately $41.4 million based on a test year calculation. The SCPSC lowered SCE&G's return on common equity from 12.45% to an amount not to exceed 11.4%, with rates set at 10.7%. The new rates became effective in January 2005. As part of its order, the SCPSC approved SCE&G's recovery of construction and operating costs for SCE&G's new Jasper County Electric Generating Station, recovery of costs of 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 the back-up dam at Lake Murray (as previously discussed at Recognition of Synthetic Fuel Tax Credits). The SCPSC also approved recovery over a five-year period of SCE&G's approximately $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization and recovery through base rates over three years of approximately $25.6 million of purchased power costs that were previously deferred. As a part of its order, the SCPSC extended through 2010 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.

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        The following table summarizes how the Company generated and used funds for property additions and construction expenditures during the three months ended March 31, 2005 and 2004:

        The Company's issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies, including state public service commissions and the Securities and Exchange Commission.

CAPITAL TRANSACTIONS

        In March 2005 SCANA issued $100 million in senior unsecured floating rate medium-term notes maturing in March 2008. The interest rate on the floating rate notes is reset quarterly based on three-month LIBOR plus 15 basis points. The proceeds from the sale, together with available cash, were used for the redemption on April 1, 2005 of $200 million of floating rate medium-term notes due to mature in November 2006.

        In March 2005 SCE&G issued $100 million first mortgage bonds having an annual interest rate of 5.25% and maturing March 1, 2035. The proceeds from the sale of these bonds were used for the redemption on April 1, 2005 of first mortgage bonds, 7.625% Series due April 1, 2025.

CAPITAL PROJECTS

        In 2001 SCE&G began construction to reinforce its Lake Murray Dam in order to comply with new federal safety standards mandated by FERC. Construction for the project and related activities is expected to cost approximately $275 million (excluding AFC) and be completed in the second quarter of 2005. Costs incurred through March 31, 2005 totaled approximately $251 million. As discussed below under Other Matters, the Company expects that substantially all of the costs of the Lake Murray Dam project will be covered by synthetic fuel tax credits.

ENVIRONMENTAL MATTERS

        In March 2005 the Environmental Protection Agency (EPA) issued a final rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxides and sulfur dioxide emissions in order to attain mandated state levels. The Company is reviewing the final rule. Installation of additional air quality controls is likely to be needed to meet the CAIR requirements. Compliance plans and cost to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates.

        In March 2005 the EPA issued a final rule establishing a mercury emissions cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. The Company is reviewing the final rule. Installation of additional air quality controls is likely to be required to comply with the mercury rule's emission caps. Compliance plans and costs to comply with

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the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates.

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

OTHER MATTERS

        Synthetic Fuel

        SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel, the use of which fuel qualifies for federal income tax credits. These synthetic fuel production facilities were placed in operation in 2000 and 2001. Under an accounting plan approved by the SCPSC in June 2000, the synthetic fuel tax credits generated by the partnerships and passed through to SCE&G, net of partnership losses and other expenses, were to be deferred until the SCPSC approved their application to offset capital costs of projects required to comply with legislative or regulatory actions.

        The aggregate investment in these partnerships as of March 31, 2005 is approximately $2.9 million, and through March 31, 2005, they have generated and passed through to SCE&G approximately $144.0 million in such tax credits. As previously described at Earnings Per Share, in a January 2005 order, the SCPSC approved SCE&G's request to apply these synthetic fuel tax credits to offset the construction costs of the Lake Murray Dam project beginning in January 2005. Under the accounting methodology approved by the SCPSC, current and future construction costs related to the project are recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation will be recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

        The level of depreciation expense and related income tax benefit recognized in the income statement will be equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of taxes. As a result, the balance of unrecovered costs in the dam remediation account will decline as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, they can have a significant impact on individual line items within the income statement.

        Depreciation on the Lake Murray Dam remediation account will be matched to available synthetic fuel tax credits on a quarterly basis until the balance in the dam remediation account is zero or until all of the available synfuel tax credits have been utilized. The Company expects to generate enough synthetic fuel tax credits in 2005, 2006 and 2007 to cover substantially all of the costs of the dam remediation project before the synthetic fuel tax credit program expires at the end of 2007.

        The ability to utilize the synthetic fuel tax credits is dependent on several factors, one of which is the average annual domestic wellhead price per barrel of crude oil as published by the U.S. Government. Under a phase-out provision included in the program, if the domestic wellhead reference price of oil per barrel falls below an inflation-adjusted benchmark range, all of the synthetic fuel tax credits that have been generated are available for use. If that price is above the benchmark range, none of the tax credits would be available. If that price falls within the benchmark range, a certain percentage of the credits would be available.

        The lower end of the inflation-adjusted benchmark range for 2004 was about $51 per barrel, while the upper end of that range was about $64. Since the reference price of oil for 2004 was less than $37, all of the synthetic fuel tax credits the Company had recorded and deferred through 2004 were available for use. While the benchmark price range for 2005 has been estimated at between $52 and $65 per barrel, the 2005 reference price will not be known until April 2006. During 2005 and subject to continuing review of the estimated benchmark range and reference price of oil for 2005, the Company

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intends to continue to record synthetic fuel tax credits as they are generated and to apply those credits quarterly to allow the recording of accelerated depreciation related to the balance in the dam remediation project account. The Company cannot predict what impact, if any, the price of oil may have on the Company's ability to earn synthetic fuel tax credits in the future.

        In order to earn these tax credits, SCANA also must be subject to a regular federal income tax liability in an amount at least equal to the credits generated in any tax year. This tax liability could be insufficient if the Company's consolidated taxable income were to be significantly reduced as the result of realizing lower income or large deductions in any tax year. The availability of these synthetic fuel tax credits is also subject to coal availability and other operational risks related to the generating plants.

        In March 2004, one of the partnerships, S. C. Coaltech No. 1 L.P. received a "No Change" letter from the Internal Revenue Service (IRS) related to its synthetic fuel operations for the tax year 2000. After review of testing procedures and supporting documentation and conducting an independent investigation, the IRS found that the partnership produces a qualifying fuel under section 29 of the Internal Revenue Code (IRC) and found no reason to challenge the first placed-in-service status of the facility. 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.

        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: