Scana 10-Q 2004 Q3 Quarterly report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM 10-Q

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2004
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period from                                to                                 

Commission File Number	Registrant, State of Incorporation, Telephone Number and Address	I.R.S. Employer Identification No.
1-8809	SCANA Corporation (a South Carolina corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000	57-0784499
1-3375	South Carolina Electric & Gas Company (a South Carolina corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000	57-0248695
1-11429	Public Service Company of North Carolina, Incorporated (a South Carolina corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000	56-2128483

        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.

Registrant	Description of Common Stock	Shares Outstanding at October 31, 2004
SCANA Corporation	Without Par Value	112,331,818
South Carolina Electric & Gas Company	$4.50 Par Value	40,296,147	(a)
Public Service Company of North Carolina, Incorporated	Without Par Value	1,000	(a)

(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

		Page
PART I. FINANCIAL INFORMATION
SCANA Corporation Financial Section		3
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of September 30, 2004 and December 31, 2003	4
	Condensed Consolidated Statements of Income for the Periods Ended September 30, 2004 and 2003	6
	Condensed Consolidated Statements of Cash Flows for the Periods Ended September 30, 2004 and 2003	7
	Condensed Consolidated Statements of Comprehensive Income for the Periods Ended September 30, 2004 and 2003	8
	Notes to Condensed Consolidated Financial Statements	9
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 4.	Controls and Procedures	35
South Carolina Electric & Gas Company Financial Section		36
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of September 30, 2004 and December 31, 2003	37
	Condensed Consolidated Statements of Income for the Periods Ended September 30, 2004 and 2003	39
	Condensed Consolidated Statements of Cash Flows for the Periods Ended September 30, 2004 and 2003	40
	Notes to Condensed Consolidated Financial Statements	41
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	50
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	57
Item 4.	Controls and Procedures	57
Public Service Company of North Carolina, Incorporated Financial Section		58
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of September 30, 2004 and December 31, 2003	59
	Condensed Consolidated Statements of Operations for the Periods Ended September 30, 2004 and 2003	60
	Condensed Consolidated Statements of Cash Flows for the Periods Ended September 30, 2004 and 2003	61
	Notes to Condensed Consolidated Financial Statements	62
Item 2.	Management's Narrative Analysis of Results of Operations	66
Item 4.	Controls and Procedures	67
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	68
Item 6.	Exhibits and Reports on Form 8-K	69
Signatures		71
Exhibit Index		72

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SCANA CORPORATION
FINANCIAL SECTION

3

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

Millions of dollars			September 30, 2004			December 31, 2003
Assets
Utility Plant In Service			$	8,281		$	7,438
Accumulated Depreciation and Amortization				(2,294	)		(2,280	)
				5,987			5,158
Construction Work in Progress				416			987
Nuclear Fuel, Net of Accumulated Amortization				26			42
Acquisition Adjustments, Net of Accumulated Amortization				230			230
Utility Plant, Net				6,659			6,417
Nonutility Property and Investments:
	Nonutility property, net of accumulated depreciation of $47 and $39			98			96
	Assets held in trust, net—nuclear decommissioning			48			44
	Other investments			150			178
	Nonutility Property and Investments, Net			296			318
Current Assets:
	Cash and temporary investments			191			117
	Receivables, net of allowance for uncollectible accounts of $11 and $16			375			503
	Receivables—affiliated companies			17			13
	Inventories (at average cost):
		Fuel		186			147
		Materials and supplies		67			60
		Emission allowances		10			6
	Prepayments			67			47
	Total Current Assets			913			893
Deferred Debits:
	Environmental			19			20
	Pension asset, net			281			270
	Other regulatory assets			357			348
	Other			184			192
	Total Deferred Debits			841			830
Total			$	8,709		$	8,458

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Millions of dollars		September 30, 2004		December 31, 2003
Capitalization and Liabilities
Shareholders' Investment:
	Common equity	$	2,442	$	2,306
	Preferred stock (Not subject to purchase or sinking funds)		106		106
	Total Shareholders' Investment		2,548		2,412
Preferred Stock, net (Subject to purchase or sinking funds)			9		9
Long-Term Debt, net			3,185		3,225
	Total Capitalization		5,742		5,646
Current Liabilities:
	Short-term borrowings		184		195
	Current portion of long-term debt		258		202
	Accounts payable		185		288
	Accounts payable—affiliated companies		18		12
	Customer deposits		44		43
	Taxes accrued		92		109
	Interest accrued		56		55
	Dividends declared		43		41
	Other		85		78
	Total Current Liabilities		965		1,023
Deferred Credits:
	Deferred income taxes, net		849		790
	Deferred investment tax credits		118		117
	Asset retirement obligation—nuclear plant		123		118
	Non-legal asset retirement obligations		446		346
	Postretirement benefits		140		135
	Other regulatory liabilities		197		173
	Other		129		110
	Total Deferred Credits		2,002		1,789
Commitments and Contingencies (Note 6)			—		—
Total		$	8,709	$	8,458

See Notes to Condensed Consolidated Financial Statements.

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SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

		Three Months Ended September 30,					Nine Months Ended September 30,
Millions of dollars, except per share amounts
		2004			2003		2004			2003
Operating Revenues:
	Electric	$	492		$	429	$	1,306		$	1,121
	Gas—regulated		162			155		776			775
	Gas—nonregulated		203			167		750			650
	Total Operating Revenues		857			751		2,832			2,546
Operating Expenses:
	Fuel used in electric generation		139			97		355			258
	Purchased power		11			13		43			39
	Gas purchased for resale		300			262		1,206			1,127
	Other operation and maintenance		142			135		440			420
	Depreciation and amortization		68			60		198			180
	Other taxes		36			34		112			104
	Total Operating Expenses		696			601		2,354			2,128
Operating Income			161			150		478			418
Other Income (Expense):
	Other income (expense), including allowance for equity funds used during construction of $2, $6, $13 and $15		(6	)		16		27			48
	Gain on sale of investments and assets		—			3		—			60
	Impairment of investments		(25	)		—		(25	)		(7	)
	Total Other Income (Expense)		(31	)		19		2			101
Income Before Interest Charges, Income Taxes and Preferred Stock Dividends			130			169		480			519
Interest Charges, Net of Allowance for Borrowed Funds Used During Construction of $2, $3, $8 and $9			50			48		151			149
Dividend Requirement of SCE&G—Obligated Mandatorily Redeemable Preferred Securities			—			—		—			2
Income Before Income Taxes and Preferred Stock Dividends			80			121		329			368
Income Tax Expense			24			35		108			120
Income Before Preferred Stock Dividends			56			86		221			248
Cash Dividends on Preferred Stock of Subsidiary			2			2		6			6
Net Income		$	54		$	84	$	215		$	242
Basic and Diluted Earnings Per Share of Common Stock		$	.48		$	.76	$	1.93		$	2.18
Weighted Average Shares Outstanding (millions)			111.8			110.9		111.3			110.9

See Notes to Condensed Consolidated Financial Statements.

6

SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

				Nine Months Ended September 30,
Millions of dollars
				2004			2003
Cash Flows From Operating Activities:
	Net income			$	215		$	242
	Adjustments to reconcile net income to net cash provided from operating activities:
		Depreciation and amortization			207			188
		Amortization of nuclear fuel			16			18
		Gain on sale of assets			—			(60	)
		Hedging activities			1			(4	)
		Impairment of investments			25			7
		Allowance for funds used during construction			(21	)		(24	)
		Changes in certain assets and liabilities:
			(Increase) decrease in receivables, net		124			116
			(Increase) decrease in inventories		(50	)		—
			(Increase) decrease in prepayments		(20	)		8
			(Increase) decrease in pension asset		(11	)		(4	)
			(Increase) decrease in other regulatory assets		(24	)		(20	)
			Increase (decrease) in deferred income taxes, net		80			27
			Increase (decrease) in regulatory liabilities		30			35
			Increase (decrease) in postretirement benefits obligations		5			2
			Increase (decrease) in accounts payable		(97	)		(82	)
			Increase (decrease) in taxes accrued		(17	)		(10	)
			Increase (decrease) in interest accrued		1			—
		Changes in fuel adjustment clauses			23			21
		Changes in other assets			2			(6	)
		Changes in other liabilities			17			9
	Net Cash Provided From Operating Activities				506			463
Cash Flows From Investing Activities:
	Utility property additions and construction expenditures, net of AFC				(327	)		(558	)
	Proceeds from sale of investments and assets				2			69
	Increase in nonutility property				(15	)		(6	)
	Investments in affiliates				(14	)		(11	)
	Net Cash Used For Investing Activities				(354	)		(506	)
Cash Flows From Financing Activities:
	Proceeds:
		Issuance of First Mortgage Bonds			—			495
		Issuance of other long-term debt			124			—
		Issuance of Pollution Control Bonds			—			36
		Issuance of common stock			47			4
	Repayments:
		Mortgage bonds			(100	)		(250	)
		Notes, loans and SCE&G Trust I Preferred Securities			(9	)		(321	)
		Pollution control bonds			—			(43	)
		Repurchase of common stock			(4	)		—
		Payment of deferred financing costs			—			(21	)
	Dividends and distributions:
		Common stock			(119	)		(113	)
		Preferred stock			(6	)		(6	)
	Short-term borrowings, net				(11	)		33
	Net Cash Used For Financing Activities				(78	)		(186	)
Net Increase (Decrease) In Cash and Temporary Investments					74			(229	)
Cash and Temporary Investments, January 1					117			305
Cash and Temporary Investments, September 30				$	191		$	76
Supplemental Cash Flow Information:
	Cash paid for—Interest (net of capitalized interest of $8 and $9)			$	151		$	149
	—Income taxes				21			63
Noncash Investing and Financing Activities:
	Unrealized gains (losses) on securities available for sale, net of tax				(1	)		1

See Notes to Condensed Consolidated Financial Statements.

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SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

		Three Months Ended September 30,					Nine Months Ended September 30,
Millions of dollars
		2004		2003			2004			2003
Net Income		$	54	$	84		$	215		$	242
Other Comprehensive Income (Loss), net of tax:
	Unrealized gains (losses) on securities available for sale		11		1			(1	)		1
	Unrealized gains (losses) on hedging activities		3		(2	)		1			(4	)
Total Comprehensive Income(1)		$	68	$	83		$	215		$	239

(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.

Millions of dollars	September 30, 2004			December 31, 2003
Accumulated deferred income taxes, net	$	109		$	110
Under- (over-) collections—electric fuel and gas cost adjustment clauses, net		15			38
Deferred purchased power costs		26			—
Deferred environmental remediation costs		19			20
Asset retirement obligation—nuclear decommissioning		49			48
Deferred non-conventional fuel tax benefits, net		(90	)		(67	)
Storm damage reserve		(33	)		(37	)
Franchise agreements		59			62
Non-legal asset retirement obligations		(446	)		(346	)
Other		25			21
Total	$	(267	)	$	(151	)

        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:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003
Net income—as reported (millions)	$	54	$	84	$	215	$	242
Net income—pro forma (millions)	$	54	$	83	$	214	$	240
Basic and diluted earnings per share—as reported	$	.48	$	.76	$	1.93	$	2.18
Basic and diluted earnings per share—pro forma	$	.48	$	.75	$	1.93	$	2.16

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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:

							Other Postretirement Benefits
	Pension Benefits
Three months ended September 30 (Millions of dollars)
	2004			2003			2004		2003
Service cost	$	2.7		$	1.9		$	0.9	$	—
Interest cost		9.3			8.3			2.9		0.5
Expected return on assets		(17.7	)		(15.0	)		—		—
Prior service cost amortization		1.7			1.5			0.5		(0.1	)
Transition obligation amortization		0.2			0.2			0.8		0.2
Amortization of actuarial loss		—			0.2			0.5		0.1
Net periodic benefit (income) cost	$	(3.8	)	$	(2.9	)	$	5.6	$	0.7

							Other Postretirement Benefits
	Pension Benefits
Nine months ended September 30 (Millions of dollars)
	2004			2003			2004		2003
Service cost	$	8.3		$	7.2		$	2.4	$	2.5
Interest cost		28.1			27.4			8.7		8.2
Expected return on assets		(53.2	)		(45.0	)		—		—
Prior service cost amortization		4.9			4.7			1.0		1.5
Transition obligation amortization		0.6			0.6			2.5		1.9
Amortization of actuarial loss		—			1.3			1.5		0.6
Net periodic benefit (income) cost	$	(11.3	)	$	(3.8	)	$	16.1	$	14.7

        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

13

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:

Rate Per Therm		Effective Date
$	.728	January-February 2003
	.928	March-October 2003
	.877	November 2003-September 2004

        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:

Rate Per Therm		Effective Date
$	.460	January-February 2003
	.595	March 2003
	.725	April-November 2003
	.600	December 2003-September 2004

        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

15

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:

Lines of credit (Millions)		SCANA			SCE&G			PSNC Energy
Committed
	Short-term	$	100			—			—
	Long-term		—		$	525		$	125
Uncommitted			113	(1)		113	(1)		—

⁽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.

Investee	Securities	Basis
		(Millions of dollars)
Magnolia Holding	6.2 million shares nonvoting common stock	$	2.1
ITC^DeltaCom	567.5 thousand shares of common stock		1.1
	170.2 thousand shares series A 8% preferred stock, convertible into 3.0 million shares of common stock		13.3
	Warrants to purchase 506.9 thousand shares of common stock		1.1
Knology	2.6 million shares of voting common stock		10.7
	2.2 million shares of nonvoting common stock		9.0
	12% senior unsecured notes due 2009		52.1
	Warrants to purchase 16.5 thousand shares of common stock		—

        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

17

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

18

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

19

$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

20

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)

Three Months Ended September 30, 2004	External Revenue			Intersegment Revenue			Operating Income (Loss)			Net Income (Loss)			Segment Assets
Electric Operations	$	492		$	1		$	168			n/a		$	5,256
Gas Distribution		114			—			(11	)		n/a			1,424
Gas Transmission		48			57			3			n/a			316
Retail Gas Marketing		70			—			n/a		$	(1	)		110
Energy Marketing		133			27			n/a			1			55
All Other		15			78			n/a			(26	)		675
Adjustments/Eliminations		(15	)		(163	)		1			80			873
Consolidated Total	$	857		$	—		$	161		$	54		$	8,709

Nine Months Ended September 30, 2004	External Revenue			Intersegment Revenue			Operating Income		Net Income (Loss)			Segment Assets
Electric Operations	$	1,306		$	3		$	385		n/a		$	5,256
Gas Distribution		622			—			38		n/a			1,424
Gas Transmission		154			238			14		n/a			316
Retail Gas Marketing		379			—			n/a	$	23		��	110
Energy Marketing		371			64			n/a		—			55
All Other		44			220			n/a		(23	)		675
Adjustments/Eliminations		(44	)		(525	)		41		215			873
Consolidated Total	$	2,832		$	—		$	478	$	215		$	8,709

Three Months Ended September 30, 2003	External Revenue			Intersegment Revenue			Operating Income (Loss)			Net Income		Segment Assets
Electric Operations	$	429		$	1		$	162			n/a	$	4,916
Gas Distribution		114			—			(15	)		n/a		1,399
Gas Transmission		41			53			3			n/a		305
Retail Gas Marketing		60			—			n/a		$	—		84
Energy Marketing		107			—			n/a			1		50
All Other		12			65			—			1		482
Adjustments/Eliminations		(12	)		(119	)		—			82		911
Consolidated Total	$	751		$	—		$	150		$	84	$	8,147

Nine Months Ended September 30, 2003	External Revenue			Intersegment Revenue			Operating Income		Net Income (Loss)			Segment Assets
Electric Operations	$	1,121		$	4		$	343		n/a		$	4,916
Gas Distribution		603			—			40		n/a			1,399
Gas Transmission		172			225			11		n/a			305
Retail Gas Marketing		320			—			n/a	$	17			84
Energy Marketing		330			—			n/a		(1	)		50
All Other		39			204			—		31			482
Adjustments/Eliminations		(39	)		(433	)		24		195			911
Consolidated Total	$	2,546		$	—		$	418	$	242		$	8,147

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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.

23

        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:

		Third Quarter					Year to Date
		2004		2003			2004		2003
Reported (GAAP) earnings per share		$	.48	$	.76		$	1.93	$	2.18
Add (Deduct):
	Gains from sales of investments and assets		—		(.02	)		—		(.35	)
	Charge related to pending litigation		.10		—			.10		—
	Investment impairments		.13		—			.13		.04
GAAP-adjusted net earnings per share from operations		$	.71	$	.74		$	2.16	$	1.87

Third Quarter 2004 vs 2003

        GAAP-adjusted net earnings per share from operations decreased primarily due to increased depreciation and amortization expense of $.05, a reduction in AFC of $.02, higher property taxes of $.01, and increased operation and maintenance expenses of $.04 and other of $.03. This is partially offset by favorable electric margins of $.12.

        GAAP earnings per share for the third quarter includes a loss of $.13 per share as a result of an impairment charge recorded on the Knology investment and a loss of $.10 resulting from a charge related to pending litigation (see Other Matters). GAAP earnings per share for 2003 includes a gain of $.02 per share in connection with the sale of ITC Holding shares and the receipt of an investment in a newly formed entity (Magnolia Holding).

Year to Date 2004 vs 2003

        GAAP-adjusted net earnings per share from operations increased primarily due to improved electric margins of $.46 and favorable results from nonregulated subsidiaries of $.10. These factors were partially offset by higher operation and maintenance expenses of $.07, higher property taxes of $.04, higher depreciation and amortization expense of $.09, increased labor and benefits of $.03 and lower gas margins of $.03.

        GAAP earnings per share year to date September 2004 includes a loss of $.13 per share as a result of an impairment charge recorded on the Knology investment and a loss of $.10 resulting from a charge related to pending litigation (see Other Matters). GAAP earnings per share year to date September 2003 includes a gain of $.35 per share in connection with the sale of ITC Holding shares and the receipt of an investment interest in a newly formed entity (Magnolia Holding) in May 2003. In the second quarter of 2003 the Company also recorded an impairment charge of $.04 per share related to the Knology investment.

25

Pension Income

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

		Third Quarter				Year to Date
Millions of dollars
		2004		2003		2004		2003
Income Statement Impact:
	Reduction in (component of) employee benefit costs	$	0.4	$	0.5	$	2.2	$	(1.7	)
	Other income		3.2		2.1		8.1		6.0
Balance Sheet Impact:
	Reduction in (component of) capital expenditures		0.1		0.2		0.7		(0.4	)
	Component of amount due to (from) Summer Station co-owner		0.1		0.1		0.3		(0.1	)
Total Pension Income		$	3.8	$	2.9	$	11.3	$	3.8

        For the last several years, the market value of the Company's retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. Pension income in 2004 increased compared to the corresponding periods in 2003 primarily as a result of a more favorable investment market.

Allowance for Funds Used During Construction (AFC)

        AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC for the nine months ended September 30, 2004 decreased slightly primarily due to completion of the Jasper County Electric Generating System in May 2004, offset by AFC resulting from the Lake Murray Dam Project.

Dividends Declared

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

Declaration Date	Dividend Per Share		Record Date	Payment Date
February 19, 2004	$	.365	March 10, 2004	April 1, 2004
April 29, 2004	$	.365	June 10, 2004	July 1, 2004
July 29, 2004	$	.365	September 10, 2004	October 1, 2004
October 29, 2004	$	.365	December 10, 2004	January 1, 2005

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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:

		Third Quarter						Year to Date
Millions of dollars
		2004		% Change		2003		2004		% Change		2003
Operating revenues		$	491.9	14.7	%	$	429.0	$	1,306.4	16.4	%	$	1,121.3
Less: Fuel used in generation			139.2	43.8	%		96.8		354.7	37.7	%		257.6
Purchased power			10.7	(16.4	)%		12.8		43.2	10.8	%		39.0
	Margin	$	342.0	7.1	%	$	319.4	$	908.5	10.2	%	$	824.7

Third Quarter 2004 vs 2003

        Margin increased due to $10.6 million from off-system sales, $9.8 million due to customer growth and consumption and $2.2 million due to favorable weather.

Year to Date 2004 vs 2003

        Margin increased primarily due to increased retail electric base rates that went into effect in February 2003, for a total impact of $7.1 million, an additional $22.7 million due to favorable weather, $34.5 million from off-system sales and $18.9 million due to customer growth and consumption.

Gas Distribution

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

		Third Quarter						Year to Date
Millions of dollars
		2004		% Change		2003		2004		% Change		2003
Operating revenues		$	114.0	0.3	%	$	113.7	$	622.0	3.4	%	$	602.6
Less: Gas purchased for resale			80.7	(0.4	)%		81.0		442.7	6.8	%		414.7
	Margin	$	33.3	1.8	%	$	32.7	$	179.3	(4.1	)%	$	187.9

Third Quarter 2004 vs 2003

        Margin increased primarily due to customer growth and increased consumption.

Year to Date 2004 vs 2003

        Margin decreased primarily due to a decreased billing surcharge for the recovery of environmental remediation expenses of $4.8 million (offset in operations and maintenance expense) and an unfavorable competitive position of natural gas relative to alternate fuels of $0.4 million at SCE&G, and a decline in customer usage per degree-day of $4.0 million, partially offset by customer growth and consumption of $2.3 million at PSNC Energy.

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Gas Transmission

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

		Third Quarter						Year to Date
Millions of dollars
		2004		% Change		2003		2004		% Change		2003
Operating revenues		$	105.9	11.6	%	$	94.9	$	392.1	(1.3	)%	$	397.4
Less: Gas purchased for resale			93.2	10.7	%		84.2		351.6	(3.0	)%		362.6
	Margin	$	12.7	18.7	%	$	10.7	$	40.5	16.4	%	$	34.8

Third Quarter 2004 vs 2003

        Margin increased primarily due to higher transportation and reservation revenue as a result of new firm transportation customers.

Year to Date 2004 vs 2003

        Margin increased primarily due to higher transportation and reservation revenue as a result of new firm transportation customers.

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:

	Third Quarter							Year to Date
Millions of dollars
	2004			% Change		2003		2004		% Change		2003
Operating revenues	$	70.1		16.6	%	$	60.1	$	379.1	18.4	%	$	320.3
Net income	$	(0.5	)	*		$	0.1	$	23.2	38.9	%	$	16.7

*

Greater than 100%

Third Quarter 2004 vs 2003

        Operating revenues increased primarily as a result of increased volumes and higher average retail prices due to higher gas costs. Net income decreased primarily due to increased operating and marketing expenses of $1.7 million, partially offset by a reduction in bad debt expense of $0.8 million.

Year to Date 2004 vs 2003

        Operating revenues increased primarily as a result of increased volumes and higher average retail prices due to higher gas costs. Net income increased primarily due to higher margins of $10.5 million, partially offset by increased bad debt expense of $1.3 million and increased operating and marketing expenses of approximately $2.7 million.

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Energy Marketing

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

	Third Quarter						Year to Date
Millions of dollars
	2004		% Change		2003		2004		% Change		2003
Operating revenues	$	159.7	49.5	%	$	106.8	$	434.1	31.6	%	$	329.8
Net income (loss)	$	1.2	71.4	%	$	0.7	$	0.2	*		$	(1.0	)

*

Greater than 100%

Third Quarter 2004 vs 2003

        Operating revenues increased primarily as a result of increased volumes. Net income increased primarily due to lower operating expenses.

Year to Date 2004 vs 2003

        Operating revenues increased primarily as a result of increased volumes. Net income increased primarily due to improved gas margins in the first and second quarters of $1.5 million partially offset by higher bad debt expense of $0.5 million.

Other Operating Expenses

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

	Third Quarter						Year to Date
Millions of dollars
	2004		% Change		2003		2004		% Change		2003
Other operation and maintenance	$	142.1	5.4	%	$	134.8	$	440.2	4.8	%	$	420.0
Depreciation and amortization		68.3	13.6	%		60.1		197.6	9.6	%		180.3
Other taxes		35.6	2.0	%		34.9		112.8	7.7	%		104.7
Total	$	246.0	7.1	%	$	229.8	$	750.6	6.5	%	$	705.0

Third Quarter 2004 vs 2003

        Other operation and maintenance expenses increased primarily due to increased labor and benefit costs of $4.6 million and $3.1 million of increased operating expenses at the generation plants. Depreciation and amortization increased $5.0 million due to the completion of the Jasper County Electric Generating Station and $2.7 million due to normal net property changes.

Year to Date 2004 vs 2003

        Other operation and maintenance expenses increased primarily due to increased labor and benefit costs of $8.2 million, 2004 winter storm restoration expenses of $2.5 million, increased expenses at electric generation plants of $5.9 million, increased bad debt of $2.8 million and gas marketing and customer billing costs of $4.4 million, partially offset by a decreased billing surcharge for the recovery of environmental remediation expenses of $4.8 million (offset in gas margin) and increased pension income of $3.8 million. Depreciation and amortization increased $8.4 million due to the completion of the Jasper County Electric Generating Station and $7.6 million due to normal net property changes. Other taxes increased primarily due to increased property taxes.

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Other Income

Third Quarter 2004 vs 2003

        Other income, including AFC, decreased primarily due to the impairment charge of the Company's Knology investment and the charge associated with pending litigation (as discussed at Earnings Per Share and Other Matters), and due to a decrease in AFC upon completion of the Jasper County Electric Generating Station in May 2004, which was somewhat offset by increased AFC resulting from expenditures on the Lake Murray Dam Project.

Year to Date 2004 vs 2003

        Other income, including AFC, decreased primarily due to the monetization and valuation of the Company's Knology investment and the charge associated with pending litigation (as discussed at Earnings Per Share and Other Matters), and due to a decrease in AFC upon completion of the Jasper County Electric Generating Station completed in May 2004, which was somewhat offset by increased AFC resulting from expenditures on the Lake Murray Dam Project.

Income Taxes

        Income taxes for the quarter and nine months ended September 30, 2004 decreased primarily as a result of changes in Other Income as discussed at Earnings Per Share.

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 September 30, 2004 was 2.67.

        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 or gas, will depend on their ability to attract the necessary financial capital on reasonable terms. Regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and these subsidiaries continue their ongoing construction programs, rate increases will be sought. The future financial position and results of operations of the regulated subsidiaries will be affected by their ability to obtain adequate and timely rate and other regulatory relief.

        On October 18, 2004 SCE&G announced that it 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 the back-up dam at Lake Murray. Similar settlements have been negotiated with several other

30

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.

     ��  The following table summarizes how the Company generated and used funds for property additions and construction expenditures during the nine months ended September 30, 2004 and 2003:

	Nine Months Ended September 30,
Millions of dollars
	2004			2003
Net cash provided from operating activities	$	506		$	463
Net cash used for financing activities		(78	)		(186	)
Cash provided from sale of investments and assets		2			69
Cash and temporary investments available at the beginning of the period		117			305
Funds used for utility property additions and construction expenditures, net of noncash allowance for funds used during construction	$	(327	)	$	(558	)
Funds used for nonutility property additions		(15	)		(6	)
Funds used for investments		(14	)		(11	)

        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.

        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:

Lines of Credit (Millions)			SCANA			SCE&G			PSNC Energy
Lines of credit:
	Committed
		Short-term	$	100			—			—
		Long-term		—		$	525		$	125
	Uncommitted			113	(1)		113	(1)		—

⁽¹⁾

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

        At September 30, 2004 SCE&G (including South Carolina Fuel Company, Inc.) and PSNC Energy had $165 million and $19 million, respectively, in short-term borrowings at weighted average interest rates of 1.80% and 1.87%, respectively.

CAPITAL TRANSACTIONS

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

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        Effective May 1, 2004 shares of SCANA's common stock purchased on behalf of participants in the SCANA Investor Plus Plan, Stock Purchase-Savings Plan and Director Compensation and Deferral Plan are being purchased directly from SCANA rather than on the open market. SCANA estimates that these original issue purchases will result in the issuance of approximately two million new shares of common stock and provide approximately $65 million in additional common stock equity on an annual basis. In addition, since March 31, 2004 SCANA has not purchased outstanding shares of common stock on the open market.

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

        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%.

CAPITAL PROJECTS

        In May 2004 SCE&G's 875 megawatt Jasper County Electric Generating Station began commercial operation. The $450 million facility includes three natural gas combustion-turbine generators and one steam-turbine generator. Approximately $276 million of the capital expenditures have been included in rate base, and the remainder is included in the rate case previously discussed.

        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. See also the previous rate case discussion.

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

ENVIRONMENTAL MATTERS

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

OTHER MATTERS

        Nuclear Station

        In April 2004 the Nuclear Regulatory Commission (NRC) approved SCE&G's application for a 20-year license extension for its V. C. Summer Nuclear Station (Summer Station). The extension allows the plant to operate through August 6, 2042.

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Synthetic Fuel

        SCE&G holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel, which fuel qualifies for federal income tax credits. The aggregate investment in these partnerships as of September 30, 2004 is approximately $3 million, and through September 30, 2004, they have generated and passed to SCE&G approximately $124 million in synthetic fuel tax credits. At September 30, 2004 SCE&G has recorded on its balance sheet $90 million net deferred tax benefits, which includes the effects of partnership losses. In addition, Primesouth, Inc, a non-regulated subsidiary of SCANA, operates a synthetic fuel facility for a third party and receives management fees, royalties and expense reimbursements related to these services. Primesouth does not benefit directly from any synfuel tax credits.

        Under a plan approved by the SCPSC, any tax credits generated by the partnerships and ultimately passed to SCE&G from synfuel produced for and consumed by SCE&G, net of partnership losses and other expenses, have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions. See Note 1A to the condensed consolidated financial statements. As discussed previously, SCE&G's rate case seeks SCPSC approval to apply current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray.

        In March 2004 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.

        Section 29 of the IRC provides for the reduction of synthetic fuel tax credits for any calendar year in which the average annual wellhead price of oil exceeds an inflation-adjusted base price per barrel (as defined in the IRC, and currently estimated to be approximately $52), up to a maximum price spread (as defined in the IRC, and currently estimated to be in the range of $12-$13), at which point the credits would be completely phased-out. 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.

Pending 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 $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.

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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.

		Expected Maturity Date
As of September 30, 2004 Millions of dollars		2004	2005	2006	2007	2008	There- After	Total	Fair Value
Liabilities
Long-Term Debt:
Fixed Rate ($)		58.0	193.6	174.4	68.6	158.6	2,640.9	3,294.1	3,375.6
Average Fixed Interest Rate (%)		7.65	7.39	8.50	6.96	6.13	6.24	6.46
Variable Rate ($)				200.0				200.0	200.0
Average Variable Interest Rate (%)				2.16				2.16
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)		54.3	3.2	3.2	28.2	118.2	122.8	329.9	6.7
	Average Pay Interest Rate (%)	7.55	5.17	5.17	5.59	4.24	4.06	4.85
	Average Receive Interest Rate (%)	7.64	8.75	8.75	7.11	5.89	6.51	6.57

        While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur.

        At September 30, 2004 the Company held investments in the 12% senior unsecured notes (due 2009) of Knology, Inc. the cost basis of which is approximately $52.1 million. As these notes are not broadly traded, determination of their fair value is not practical.

        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:

	Futures Contracts
				Options Purchased Call (Long) ($)
	Long ($)	Short ($)
2004
Settlement Price(a)	7.19	7.22
Contract Amount	17.1	3.3	Strike Price(a)	8.61
Fair Value	20.7	3.8	Contract Amount	20.0
2005
Settlement Price(a)	7.55	7.98
Contract Amount	21.9	2.5
Fair Value	27.3	3.0
2006
Settlement Price(a)	6.98	—
Contract Amount	0.5	—
Fair Value	0.8	—

^(a)

Weighted average

        Equity price risk—Investments in telecommunications companies' equity securities (excluding preferred stock with significant debt characteristics) are carried at market value or, if market value is not readily determinable, at cost. The carrying value of the Company's investments in such securities totaled $25.0 million at September 30, 2004. A temporary decline in value of ten percent would result in a $2.5 million reduction in fair value and a corresponding adjustment, net of tax effect, to the related equity account for unrealized gains/losses, a component of Other Comprehensive Income (Loss). An other than temporary decline in value of ten percent would result in a $2.5 million reduction in fair value and a corresponding adjustment to net income, net of tax effect.

Item 4.    Controls and Procedures

        As of September 30, 2004 an evaluation was performed under the supervision and with the participation of the Company's management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Company's management, including the CEO and CFO, concluded that as of September 30, 2004 the Company's disclosure controls and procedures were effective. There has been no change in the Company's internal control over financial reporting during the quarter ended September 30, 2004 that has materially affected or is reasonably likely to materially affect the Company's internal control over financial reporting.

35

SOUTH CAROLINA ELECTRIC & GAS COMPANY
FINANCIAL SECTION

36

Item 1.    Financial Statements

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

Millions of dollars			September 30, 2004			December 31, 2003
Assets
Utility Plant In Service			$	7,020		$	6,207
Accumulated Depreciation and Amortization				(1,900	)		(1,907	)
				5,120			4,300
Construction Work in Progress				369			951
Nuclear Fuel, Net of Accumulated Amortization				26			42
Utility Plant, Net				5,515			5,293
Nonutility Property and Investments:
	Nonutility property, net of accumulated depreciation			25			19
	Assets held in trust, net—nuclear decommissioning			48			44
	Other investments			6			6
	Nonutility Property and Investments, Net			79			69
Current Assets:
	Cash and temporary investments			12			56
	Receivables, net			234			238
	Receivables—affiliated companies			22			61
	Inventories (at average cost):
		Fuel		35			35
		Materials and supplies		61			54
		Emission allowances		10			6
	Prepayments			26			20
	Total Current Assets			400			470
Deferred Debits:
	Environmental			11			11
	Pension asset, net			281			270
	Due from affiliates—pension and postretirement benefits			22			20
	Other regulatory assets			334			333
	Other			155			162
	Total Deferred Debits			803			796
Total			$	6,797		$	6,628

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Millions of dollars		September 30, 2004		December 31, 2003
Capitalization and Liabilities
Shareholders' Investment:
	Common equity	$	2,147	$	2,043
	Preferred stock (Not subject to purchase or sinking funds)		106		106
	Total Shareholders' Investment		2,253		2,149
Preferred Stock, net (Subject to purchase or sinking funds)			9		9
Long-Term Debt, net			1,976		2,010
Total Capitalization			4,238		4,168
Minority Interest			77		100
Current Liabilities:
	Short-term borrowings		165		140
	Current portion of long-term debt		198		142
	Accounts payable		71		104
	Accounts payable—affiliated companies		61		134
	Customer deposits		25		25
	Taxes accrued		85		118
	Interest accrued		37		39
	Dividends declared		38		43
	Other		34		42
	Total Current Liabilities		714		787
Deferred Credits:
	Deferred income taxes, net		761		707
	Deferred investment tax credits		116		114
	Asset retirement obligation—nuclear plant		123		118
	Non-legal asset retirement obligations		360		265
	Due to affiliates—pension and postretirement benefits		14		15
	Postretirement benefits		140		135
	Other regulatory liabilities		185		164
	Other		69		55
	Total Deferred Credits		1,768		1,573
Commitments and Contingencies (Note 5)			—		—
Total		$	6,797	$	6,628

See Notes to Condensed Consolidated Financial Statements.

38

SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

		Three Months Ended September 30,				Nine Months Ended September 30,
Millions of dollars
		2004		2003		2004		2003
Operating Revenues:
	Electric	$	493	$	430	$	1,310	$	1,125
	Gas		62		54		275		259
	Total Operating Revenues		555		484		1,585		1,384
Operating Expenses:
	Fuel used in electric generation		139		97		355		258
	Purchased power		11		13		43		39
	Gas purchased for resale		51		44		217		194
	Other operation and maintenance		103		96		315		303
	Depreciation and amortization		57		49		164		148
	Other taxes		32		31		102		95
	Total Operating Expenses		393		330		1,196		1,037
Operating Income			162		154		389		347
Other Income, Including Allowance for Equity Funds Used During Construction of $2, $5, $11 and $14			5		9		19		24
Income Before Interest Charges, Minority Interest, Income Taxes and Preferred Stock Dividends			167		163		408		371
Interest Charges, Net of Allowance for Borrowed Funds Used During Construction of $2, $3, $7 and $8			34		33		104		101
Dividend Requirement of Company—Obligated Mandatorily Redeemable Preferred Securities			—		—		—		2
Income Before Minority Interest, Income Taxes and Preferred Stock Dividends			133		130		304		268
Minority Interest			2		2		5		5
Income Before Taxes and Preferred Stock Dividends			131		128		299		263
Income Tax Expense			46		40		104		88
Net Income			85		88		195		175
Preferred Stock Cash Dividends Declared			2		2		6		6
Earnings Available for Common Shareholder		$	83	$	86	$	189	$	169

See Notes to Condensed Consolidated Financial Statements.

39

SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

				Nine Months Ended September 30,
Millions of dollars
				2004			2003
Cash Flows From Operating Activities:
	Net income			$	195		$	175
	Adjustments to reconcile net income to net cash provided from operating activities:
		Minority interest			5			5
		Depreciation and amortization			164			148
		Amortization of nuclear fuel			16			18
		Allowance for funds used during construction			(18	)		(22	)
		Changes in certain assets and liabilities:
			(Increase) decrease in receivables, net		43			7
			(Increase) decrease in inventories		(11	)		30
			(Increase) decrease in prepayments		(6	)		4
			(Increase) decrease in pension asset		(11	)		(4	)
			(Increase) decrease in other regulatory assets		(23	)		(20	)
			Increase (decrease) in deferred income taxes, net		52			34
			Increase (decrease) in regulatory liabilities		27			33
			Increase (decrease) in postretirement benefits obligations		5			2
			Increase (decrease) in accounts payable		(106	)		(29	)
			Increase (decrease) in taxes accrued		(33	)		3
			Increase (decrease) in interest accrued		(2	)		4
		Changes in fuel adjustment clauses			30			26
		Changes in other assets			(5	)		(1	)
		Changes in other liabilities			17			4
	Net Cash Provided From Operating Activities				339			417
Cash Flows From Investing Activities:
	Utility property additions and construction expenditures, net of AFC				(281	)		(496	)
	Increase in nonutility property				(5	)		—
	Proceeds from sale of assets				2			—
	Investments in affiliates				(14	)		(11	)
	Net Cash Used For Investing Activities				(298	)		(507	)
Cash Flows From Financing Activities:
	Proceeds:
		Issuance of First Mortgage Bonds			—			495
		Pollution Control Bonds			—			36
		Other long-term debt			124			—
		Distributions from parent			21			57
	Repayments:
		Mortgage Bonds			(100	)		(250	)
		Pollution Control Bonds			—			(43	)
		Other long-term debt			(2	)		(11	)
		SCE&G Trust I Preferred Securities			—			(50	)
		Payment of deferred financing costs			—			(21	)
	Dividends and distributions:
		Common stock			(118	)		(115	)
		Preferred stock			(6	)		(6	)
		Distribution to parent			(29	)		—
	Short-term borrowings, net				25			18
	Net Cash Provided From (Used For) Financing Activities				(85	)		110
Net Increase (Decrease) In Cash and Temporary Investments					(44	)		20
Cash and Temporary Investments, January 1					56			23
Cash and Temporary Investments, September 30				$	12		$	43
Supplemental Cash Flow Information:
	Cash paid for—Interest (net of capitalized interest of $7 and $8)			$	100		$	90
—Income taxes					30			8

See Notes to Condensed Consolidated Financial Statements.

40

SOUTH CAROLINA ELECTRIC & GAS COMPANY
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 South Carolina Electric & Gas Company's (together with its consolidated affiliates, 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.    Variable Interest Entity

        The Company adopted Financial Accounting Standards Board Interpretation No. 46 (Revised 2003) (FIN 46), "Consolidation of Variable Interest Entities", effective January 1, 2004, which requires an enterprise's consolidated financial statements to include entities in which the enterprise has a controlling financial interest. South Carolina Electric and Gas Company (SCE&G) has determined that it has a controlling financial interest in South Carolina Generating Company, Inc. (GENCO) under the criteria of FIN 46, and accordingly, the accompanying condensed consolidated financial statements include the accounts of SCE&G, GENCO and South Carolina Fuel Company, Inc. Prior period amounts have been restated to reflect the adoption of FIN 46. The consolidation resulted in an increase of approximately $327 million in net assets reflected in the condensed consolidated balance sheet as of September 30, 2004. The equity interest in GENCO is held solely by SCANA Corporation, the Company's parent. Accordingly, GENCO's equity and results of operations are reflected as a minority interest in the Company's condensed consolidated financial statements, and the adoption of FIN 46 therefore had no impact on the Company's equity, net earnings or cash flows.

        GENCO owns and operates a coal-fired electric generating station with a 615 megawatt net generating capacity (summer rating). GENCO's electricity is sold solely to SCE&G under the terms of a power purchase and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO's property (carrying value of approximately $77 million) serves as collateral for its long-term borrowings.

B.    Basis of Accounting

        The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71, "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,

41

approximately $345 million and $545 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.

Millions of dollars	September 30, 2004			December 31, 2003
Accumulated deferred income taxes, net	$	103		$	104
Under- (over-) collections—electric fuel and gas cost adjustment clauses, net		9			39
Deferred purchased power costs		26			—
Deferred environmental remediation costs		11			11
Asset retirement obligation—nuclear decommissioning		49			48
Deferred non-conventional fuel tax benefits, net		(90	)		(67	)
Storm damage reserve		(33	)		(37	)
Franchise agreements		59			62
Non-legal asset retirement obligations		(360	)		(265	)
Other		26			20
Total	$	(200	)	$	(85	)

        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) during annual hearings.

        Deferred purchased power costs—In April 2004 the SCPSC approved a stipulation agreement between the Consumer Advocate and SCE&G whereby SCE&G was allowed to defer for recovery in a future rate proceeding the portion of the purchased power costs not allowed to be recovered through the fuel clause. In 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 SCE&G. 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.

        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 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 capped at $50 million to be collected through rates over a period of approximately ten years. The accumulated storm damage

42

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 has 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 the SCPSC. 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 SCE&G. However, ultimate recovery is subject to SCPSC approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company's results of operations, liquidity or financial position in the period the write-off would be recorded.

C.    Affiliated Transactions

        SCE&G has entered into agreements with certain affiliates to purchase gas for resale to its distribution customers. SCE&G purchases all of its natural gas requirements from South Carolina Pipeline Corporation (SCPC). SCE&G had approximately $17.5 million and $39.5 million payable to SCPC for such gas purchases at September 30, 2004 and December 31, 2003, respectively.

        The Company holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel. The Company had recorded as receivables from these affiliated companies for these investments approximately $17.4 million and $13.4 million at September 30, 2004 and December 31, 2003, respectively. The Company 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.

43

D.    Pension and Other Postretirement Benefit Plans

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

							Other Postretirement Benefits
	Pension Benefits
Three months ended September 30 (Millions of dollars)
	2004			2003			2004			2003
Service cost	$	2.7		$	1.9		$	0.9		$	—
Interest cost		9.3			8.3			2.9			0.5
Expected return on assets		(17.7	)		(15.0	)		—			—
Prior service cost amortization		1.7			1.5			0.5			(0.1	)
Transition obligation amortization		0.2			0.2			0.8			0.2
Amortization of actuarial loss		—			0.2			0.5			0.1
Amount attributable to Company affiliates		(0.5	)		(0.3	)		(1.5	)		(0.2	)
Net periodic benefit (income) cost	$	(4.3	)	$	(3.2	)	$	4.1		$	0.5

							Other Postretirement Benefits
	Pension Benefits
Nine months ended September 30 (Millions of dollars)
	2004			2003			2004			2003
Service cost	$	8.3		$	7.2		$	2.4		$	2.5
Interest cost		28.1			27.4			8.7			8.2
Expected return on assets		(53.2	)		(45.0	)		—			—
Prior service cost amortization		4.9			4.7			1.0			1.5
Transition obligation amortization		0.6			0.6			2.5			1.9
Amortization of actuarial loss		—			1.3			1.5			0.6
Amount attributable to Company affiliates		(1.3	)		(1.3	)		(4.4	)		(4.0	)
Net periodic benefit (income) cost	$	(12.6	)	$	(5.1	)	$	11.7		$	10.7

        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 actually 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.

E.    Reclassifications

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

44

2.     RATE AND OTHER REGULATORY MATTERS

        Electric

        On October 18, 2004 SCE&G announced that it 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 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.

45

        SCE&G's cost of gas component in effect during the period January 1, 2003 through September 30, 2004 was as follows:

Rate Per Therm		Effective Date
$	.728	January-February 2003
	.928	March-October 2003
	.877	November 2003-September 2004

        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.

3.     DEBT AND CREDIT FACILITIES

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

        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 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 $525 million. These new revolving credit facilities replaced $475 million in existing committed credit facilities.

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

4.     RETAINED EARNINGS

        SCE&G's Restated Articles of Incorporation 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 common stock.

46

5.     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 SCE&G 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. If such an incident were to occur, it would have a material adverse impact on SCE&G's results of operations, cash flows and financial position.

C.    Environmental

        SCE&G 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.

        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.

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        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 owned 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.

D.    Claims and Litigation

        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. SCE&G is confident of the propriety of its actions and intends to mount a vigorous defense. SCE&G 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, SCE&G 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 that SCE&G 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 SCE&G'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. SCE&G believes its actions are consistent with governing law and the applicable documents granting easements and rights-of-way. SCE&G 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

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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 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.

6.     SEGMENT OF BUSINESS INFORMATION

        The Company's reportable segments are listed in the following table. The Company uses operating income to measure profitability for its regulated operations. Therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. Intersegment revenues were not significant.

Disclosure of Reportable Segments
(Millions of Dollars)

Three Months Ended September 30,	2004							2003
	External Revenue		Operating Income (Loss)			Segment Assets		External Revenue		Segment Assets			Operating Income (Loss)
Electric Operations	$	493	$	168		$	5,256	$	430	$	163		$	4,929
Gas Distribution		62		(4	)		340		54		(8	)		319
Adjustments/Eliminations		—		(2	)		1,201		—		(1	)		1,122
Consolidated Total	$	555	$	162		$	6,797	$	484	$	154		$	6,370

Nine Months Ended September 30,	2004							2003
	External Revenue		Operating Income (Loss)			Segment Assets		External Revenue		Operating Income (Loss)			Segment Assets
Electric Operations	$	1,310	$	385		$	5,256	$	1,125	$	343		$	4,929
Gas Distribution		275		6			340		259		5			319
Adjustments/Eliminations		—		(2	)		1,201		—		(1	)		1,122
Consolidated Total	$	1,585	$	389		$	6,797	$	1,384	$	347		$	6,370

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Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations

SOUTH CAROLINA ELECTRIC & GAS COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        The following discussion should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in South Carolina Electric & Gas Company's (together with its consolidated affiliates, 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 regulatory environment, (3) current and future litigation, (4) changes in the economy, especially in the Company's service territory, (5) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (6) growth opportunities, (7) the results of financing efforts, (8) changes in the Company's accounting policies, (9) weather conditions, especially in areas served by the Company, (10) performance of SCANA Corporation's (SCANA) pension plan assets and the impact on the Company's results of operations, (11) inflation, (12) changes in environmental regulations and (13) 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.

        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

50

working closely with FERC to implement stronger reliability standards among NERC's voluntary membership. SCE&G, along with other NERC members, is also working closely with NERC in these efforts. Such initiatives 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.

RESULTS OF OPERATIONS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2004
AS COMPARED TO THE CORRESPONDING PERIODS IN 2003

Net Income

        Net income for the periods ended September 30, 2004 and 2003 was as follows:

	Third Quarter				Year to Date
Millions of dollars
	2004		2003		2004		2003
Net income	$	84.4	$	87.8	$	195.0	$	174.8

Third Quarter 2004 vs 2003

        Net income decreased primarily due to increased operation and maintenance expense of $4.1 million, higher depreciation expense of $4.8 million, lower AFC of $3.7 million and larger tax deductions in 2003 than in 2004 for certain removal costs. This was partially offset by higher electric margins of $14.1 million.

Year to Date 2004 vs 2003

        Net income increased due to higher electric margins of $51.4 million and a reduction of preferred dividend requirements of $1.7 million, partially offset by lower gas margins of $3.7 million, higher operation and maintenance expense of $7.1 million, higher depreciation expense of $10.0 million, higher taxes other than income (primarily property taxes) of $4.7 million and lower AFC of $2.7 million.

Pension Income

        Pension income was recorded on SCE&G's financial statements as follows:

		Third Quarter				Year to Date
Millions of dollars
		2004		2003		2004		2003
Income Statement Impact:
	Reduction in (component of) employee benefit costs	$	0.8	$	0.7	$	3.1	$	(0.7	)
	Other income		3.2		2.2		8.3		6.1
Balance Sheet Impact:
	Reduction in (component of) capital expenditures		0.2		0.2		0.9		(0.2	)
	Component of amount due to (from) Summer Station co-owner		0.1		0.1		0.3		(0.1	)
Total Pension Income		$	4.3	$	3.2	$	12.6	$	5.1

        For the last several years, the market value of SCANA's retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. SCE&G's portion of SCANA's

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pension income in 2004 increased compared to the corresponding periods in 2003 primarily as a result of a more favorable investment market.

Allowance for Funds Used During Construction (AFC)

        AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. The decrease in AFC for the quarter ended September 30, 2004 is primarily due to completion of the construction of the Jasper County Electric Generating Station in May 2004. AFC for the nine months ending September 30, 2004 decreased, primarily due to completion of the Jasper County Electric Generating Station in May 2004, offset by the increase in AFC resulting from the Lake Murray Dam Project.

Dividends Declared

        SCE&G's and South Carolina Generating Company, Inc.'s (GENCO) Boards of Directors have declared the following dividends on common stock held by SCANA during 2004:

Declaration Date	Amount		Quarter Ended	Payment Date
February 19, 2004	$	36.0 million	March 31, 2004	April 1, 2004
April 29, 2004	$	37.0 million	June 30, 2004	July 1, 2004
July 29, 2004	$	36.0 million	September 30, 2004	October 1, 2004
October 29, 2004	$	36.5 million	December 31, 2004	January 1, 2005

Electric Operations

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

		Third Quarter						Year to Date
Millions of dollars
		2004		% Change		2003		2004		% Change		2003
Operating revenues		$	493.0	14.7	%	$	429.8	$	1,309.5	16.4	%	$	1,125.0
Less: Fuel used in generation			139.2	43.8	%		96.8		354.7	37.7	%		257.6
Purchased power			10.7	(16.4	)%		12.8		43.1	10.8	%		39.0
	Margin	$	343.1	7.1	%	$	320.2	$	911.7	10.0	%	$	828.4

Third Quarter 2004 vs 2003

        Margin increased primarily due to $10.6 million from off-system sales, $10.1 million due to customer growth and consumption, and $2.2 million due to favorable weather.

Year to Date 2004 vs 2003

        Margin increased primarily due to increased retail electric base rates that went into effect in February 2003, for a total impact of $7.1 million, an additional $22.7 million due to favorable weather, $34.5 million from off-system sales and $18.9 million due to customer growth and consumption.

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Gas Distribution

        Gas Distribution is comprised of the local distribution operations of SCE&G. Gas distribution sales margins (including transactions with affiliates) were as follows:

		Third Quarter						Year to Date
Millions of dollars
		2004		% Change		2003		2004		% Change		2003
Operating revenues		$	61.5	12.6	%	$	54.6	$	275.1	6.4	%	$	258.6
Less: Gas purchased for resale			50.5	15.3	%		43.8		216.6	11.6	%		194.1
	Margin	$	11.0	1.9	%	$	10.8	$	58.5	(9.3	)%	$	64.5

Third Quarter 2004 vs 2003

        Margin increased due to customer growth partially offset by a decreased billing surcharge for the recovery of environmental remediation expenses (offset in operations and maintenance expense).

Year to Date 2004 vs 2003

        Margin decreased primarily due to a decreased billing surcharge for the recovery of environmental remediation expenses of $4.8 million (offset in operations and maintenance expense) and an unfavorable competitive position of natural gas relative to alternate fuels of $0.4 million.

Other Operating Expenses

        Other operating expenses were as follows:

	Third Quarter						Year to Date
Millions of dollars
	2004		% Change		2003		2004		% Change		2003
Other operation and maintenance	$	103.0	7.0	%	$	96.3	$	315.2	3.8	%	$	303.6
Depreciation and amortization		57.2	15.6	%		49.5		164.6	10.9	%		148.3
Other taxes		32.2	2.2	%		31.5		101.9	7.9	%		94.4
Total	$	192.4	8.5	%	$	177.3	$	581.7	6.5	%	$	546.3

Third Quarter 2004 vs 2003

        Other operation and maintenance expenses increased primarily due to $3.1 million of increased operating expense at the electric generation plants and $4.6 million in labor and benefits. Depreciation and amortization expense increased $5.0 million due to the completion of the Jasper County Electric Generating Station and $2.7 million due to normal net property changes.

Year to Date 2004 vs 2003

        Other operation and maintenance expenses increased primarily due to increased labor and benefit costs of $6.7 million, 2004 winter storm restoration expenses of $2.5 million, increased expenses at electric generation plants of $5.9 million and other operating expenses of $1.9 million partially offset by a decreased billing surcharge for the recovery of environmental remediation expenses of $4.8 million (offset in gas margin) and increased pension income of $3.8 million. Depreciation and amortization expense increased $8.4 million due to the completion of the Jasper County Electric Generating Station and $7.6 million due to normal net property changes. Other taxes increased primarily due to increased property taxes.

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Interest Expense

        Interest expense for the quarter increased primarily due to reduced AFC. Interest expense year to date increased primarily due to increased long-term debt.

Income Taxes

        Income taxes for the quarter increased primarily as a result of changes in operating income and larger tax deductions in 2003 than in 2004 for certain removal costs. Income taxes year to date increased primarily due to changes in operating income.

LIQUIDITY AND CAPITAL RESOURCES

        The Company anticipates that its contractual cash obligations will be met through internally generated funds and the incurrence of additional short-term and long-term indebtedness. 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 September 30, 2004 was 4.37.

        The Company's cash requirements arise primarily from its operational needs, funding its construction programs and payment of dividends to SCANA. The ability of the Company to replace existing plant investment, as well as to expand to meet future demand for electricity and gas, will depend upon its ability to attract the necessary financial capital on reasonable terms. SCE&G recovers the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and SCE&G continues its ongoing construction program, SCE&G expects to seek increases in rates. SCE&G's future financial position and results of operations will be affected by its ability to obtain adequate and timely rate and other regulatory relief.

        On October 18, 2004 SCE&G announced that it 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 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.

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        The following table summarizes how SCE&G generated and used funds for property additions and construction expenditures during the nine months ended September 30, 2004 and 2003:

	Nine Months Ended September 30,
Millions of dollars
	2004			2003
Net cash provided from operating activities	$	339		$	417
Net cash provided from (used for) financing activities		(85	)		110
Cash provided from sale of assets		2			—
Cash and temporary cash investments available at the beginning of the period		56			23
Funds used for utility property additions and construction expenditures, net of noncash allowance for funds used during construction	$	(281	)	$	(496	)
Funds used for nonutility property additions		(5	)		—
Funds used for investments		(14	)		(11	)

        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. The following describes the revolving credit programs currently utilized by the Company.

        In June 2004 the Company entered into new five-year revolving committed credit facilities totaling $525 million. These new revolving credit facilities replaced $475 million in existing committed credit facilities. The Company had available the following revolving credit facilities which were unused at September 30, 2004:

(Millions)
Lines of credit:
	Committed	$	525
	Uncommitted		113	(1)

⁽¹⁾

Either SCE&G or SCANA may use this uncommitted line.

        At September 30, 2004 SCE&G had $165 million in outstanding short-term borrowings at a weighted average interest rate of 1.80%.

CAPITAL TRANSACTIONS

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

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

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

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CAPITAL PROJECTS

        In May 2004 SCE&G's 875 megawatt Jasper County Electric Generating Station began commercial operation. The $450 million facility includes three natural gas combustion-turbine generators and one steam-turbine generator. Approximately $276 million of the capital expenditures have been included in rate base, and the remainder is included in the rate case previously discussed.

        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. See also the previous rate case discussion.

ENVIRONMENTAL MATTERS

        For information on environmental matters see Note 5C to condensed consolidated financial statements.

OTHER MATTERS

Nuclear Station

        In April 2004 the Nuclear Regulatory Commission (NRC) approved SCE&G's application for a 20-year license extension for its V. C. Summer Nuclear Station (Summer Station). The extension allows the plant to operate through August 6, 2042.

Synthetic Fuel

        SCE&G holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel, which fuel qualifies for federal income tax credits. The aggregate investment in these partnerships as of September 30, 2004 is approximately $3 million, and through September 30, 2004, they have generated and passed through to SCE&G approximately $124 million in synthetic fuel tax credits. At September 30, 2004 SCE&G has recorded on its balance sheet $90 million net deferred tax benefits, which includes the effects of partnership losses.

        Under a plan approved by the SCPSC, any tax credits generated by the partnerships and ultimately passed to SCE&G from synfuel produced for and consumed by SCE&G, net of partnership losses and other expenses, have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions. See Note 1B to condensed consolidated financial statements. As discussed previously, SCE&G's rate case seeks SCPSC approval to apply current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray.

        In March 2004 S.C. Coaltech No. l 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 SCANA's position that the synthetic fuel tax credits have been properly claimed.

        Section 29 of the IRC provides for the reduction of synthetic fuel tax credits for any calendar year in which the average annual wellhead price of oil exceeds an inflation-adjusted base price per barrel (as defined in the IRC, and currently estimated to be approximately $52), up to a maximum price spread (as defined in the IRC, and currently estimated to be in the range of $12-$13), at which point the credits would be completely phased-out. 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.

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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 SCE&G which is 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. Fair values for debt represent quoted market prices.

	Expected Maturity Date
As of September 30, 2004 Millions of dollars	2004	2005	2006	2007	2008	There- after	Total	Fair Value
Liabilities
Long-Term Debt:
Fixed Rate ($)	3.7	189.2	169.9	39.2	39.2	1,821.9	2,263.1	2,236.7
Average Interest Rate (%)	7.78	7.37	8.51	6.86	6.86	6.03	6.36

        While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur.

Item 4.    Controls and Procedures

        As of September 30, 2004 an evaluation was performed under the supervision and with the participation of the Company's management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Company's management, including the CEO and CFO, concluded that as of September 30, 2004 the Company's disclosure controls and procedures were effective. There has been no change in the Company's internal control over financial reporting during the quarter ended September 30, 2004 that has materially affected or is reasonably likely to materially affect the Company's internal control over financial reporting.

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PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
FINANCIAL SECTION

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).

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Item 1.    Financial Statements.

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

Millions of dollars			September 30, 2004			December 31, 2003
Assets
Gas Utility Plant			$	955		$	923
Accumulated Depreciation				(272	)		(256	)
Acquisition Adjustment, Net of Accumulated Amortization				210			210
Gas Utility Plant, Net				893			877
Nonutility Property and Investments, Net				27			28
Current Assets:
	Cash and temporary investments			2			18
	Restricted cash and temporary investments			8			7
	Receivables, net of allowance for uncollectible accounts of $1 and $2			32			115
	Receivables—affiliated companies			2			5
	Inventories (at average cost):
		Stored gas		69			56
		Materials and supplies		5			5
	Prepayments			10			2
	Deferred income taxes, net			5			3
	Total Current Assets			133			211
Deferred Debits:
	Due from affiliate—pension asset			12			13
	Regulatory assets			23			17
	Other			5			6
	Total Deferred Debits			40			36
Total			$	1,093		$	1,152
Capitalization and Liabilities
Capitalization:
	Common equity		$	506		$	502
	Long-term debt, net			274			278
	Total Capitalization			780			780
Current Liabilities:
	Short-term borrowings			19			55
	Current portion of long-term debt			8			8
	Accounts payable			22			48
	Accounts payable—affiliated companies			4			2
	Customer deposits			7			7
	Taxes accrued			5			10
	Interest accrued			3			6
	Distributions/dividends declared			3			4
	Other			18			15
	Total Current Liabilities			89			155
Deferred Credits:
	Deferred income taxes, net			101			96
	Deferred investment tax credits			1			2
	Due to affiliate-postretirement benefits			18			17
	Other regulatory liabilities			12			9
	Non-legal asset retirement obligations			82			77
	Other			10			16
	Total Deferred Credits			224			217
Commitments and Contingencies (Note 5)				—			—
Total			$	1,093		$	1,152

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

		Three Months Ended September 30,						Nine Months Ended September 30,
Millions of dollars
		2004			2003			2004		2003
Operating Revenues		$	53		$	59		$	348	$	344
Cost of Gas			30			37			226		221
Gross Margin			23			22			122		123
Operating Expenses:
	Operation and maintenance		18			19			58		57
	Depreciation		9			9			26		26
	Other taxes		2			2			6		5
	Total Operating Expenses		29			30			90		88
Operating Income (Loss)			(6	)		(8	)		32		35
Other Income, Including Allowance for Equity Funds Used During Construction			1			2			4		6
Interest Charges, Net of Allowance for Borrowed Funds Used During Construction			5			5			15		16
Income (Loss) Before Income Tax Expense (Benefit)			(10	)		(11	)		21		25
Income Tax Expense (Benefit)			(4	)		(4	)		8		9
Net Income (Loss)		$	(6	)	$	(7	)	$	13	$	16

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

				Nine Months Ended September 30,
Millions of dollars
				2004			2003
Cash Flows From Operating Activities:
	Net income			$	13		$	16
	Adjustments to reconcile net income to net cash provided from operating activities:
		Depreciation and amortization			27			28
		Loss on sale of assets			1			—
		Allowance for funds used during construction			(1	)		(1	)
		Changes in certain assets and liabilities:
			(Increase) decrease in receivables, net		86			61
			(Increase) decrease in inventories		(13	)		(23	)
			(Increase) decrease in regulatory assets		1			—
			Increase (decrease) in regulatory liabilities		1			—
			Increase (decrease) in accounts payable		(24	)		(20	)
			Increase (decrease) in deferred income taxes, net		3			5
			Increase (decrease) in taxes accrued		(5	)		—
		Changes in gas adjustment clauses			(6	)		(5	)
		Changes in other assets			(7	)		(5	)
		Changes in other liabilities			(1	)		(4	)
Net Cash Provided From Operating Activities					75			52
Cash Flows From Investing Activities:
	Construction expenditures				(39	)		(36	)
	Nonutility and other				(1	)		(1	)
Net Cash Used For Investing Activities					(40	)		(37	)
Cash Flows From Financing Activities:
	Short-term borrowings, net				(36	)		4
	Capital contribution from parent				—			3
	Retirement of long-term debt				(3	)		(3	)
	Distributions/dividend payments				(12	)		(15	)
Net Cash Used For Financing Activities					(51	)		(11	)
Net Increase (Decrease) In Cash and Temporary Investments					(16	)		4
Cash and Temporary Investments, January 1					18			1
Cash and Temporary Investments, September 30				$	2		$	5
Supplemental Cash Flow Information:
Cash paid for—Interest (net of capitalized interest of $1 and $1)				$	16		$	16
—Income taxes				$	20			14

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
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 Public Service Company of North Carolina, Incorporated's (together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, 2003. These are interim financial statements, and due to the seasonality of the Company's business, the amounts reported in the Condensed Consolidated Statements of Operations are not necessarily indicative of amounts expected for the year. In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature, which are necessary for a fair statement of the results for the interim periods reported.

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.    Basis of Accounting

        The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation." SFAS 71 requires cost-based rate-regulated utilities to recognize in their financial statements 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 $23 million and $94 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.

Millions of dollars	September 30, 2004			December 31, 2003
Excess deferred income taxes	$	(2	)		—
Under- (over-) collections—gas cost adjustment clause, net		5		$	(1	)
Deferred environmental remediation costs		8			9
Non-legal asset retirement obligations		(82	)		(77	)
Total	$	(71	)	$	(69	)

        Excess deferred income taxes represent deferred income taxes recorded in prior years at a rate higher than the current statutory rate. Pursuant to a North Carolina Utilities Commission (NCUC) order, the Company is required to refund these amounts to customers through a rate decrement.

        Under- (over-) collections-gas cost adjustment clause, net represents amounts under- or over-collected from customers pursuant to the Company's Rider D mechanism approved by the NCUC. This mechanism allows the Company to recover all prudently incurred gas costs.

        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. A portion of the costs incurred has been recovered through rates. Approximately $1.2 million in costs, net of insurance settlements, have been incurred and deferred for subsequent rate consideration. (See Note 5.) Management believes that all MGP cleanup costs will be recoverable through gas rates.

        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 NCUC has 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 the NCUC.

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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 NCUC approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company's results of operations, liquidity or financial position in the period the write-off would be recorded.

B.    Total Comprehensive Income

        Total comprehensive income was not significantly different from net income for any period reported. Accumulated other comprehensive income (loss) of the Company totaled $(0.8) million and $(0.9) million as of September 30, 2004 and December 31, 2003, respectively.

C.    Reclassifications

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

2.     RATE AND OTHER REGULATORY MATTERS

        The Company's rates are established using a benchmark cost of gas approved by the NCUC, which may be modified periodically to reflect changes in the market price of natural gas. The Company 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 the Company's gas purchasing practices annually.

        The Company's benchmark cost of gas in effect during the period January 1, 2003 through September 30, 2004 was as follows:

Rate Per Therm		Effective Date
$	.460	January-February 2003
	.595	March 2003
	.725	April-November 2003
	.600	December 2003-September 2004

        On October 1, 2004 the NCUC approved the Company'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 the Company's 2004 Annual Prudence Review, the NCUC determined that the Company'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 the Company to implement decrements in its sales and transportation rate schedules to reflect a decrease of approximately $5.7 million in the Company'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 the Company's interstate pipeline transporters, provides financing for expansion into areas that otherwise would not be economically feasible to serve. In June 2000 the NCUC approved the Company's requests for disbursement of up to $28.4 million from the Company's expansion fund to extend natural gas service to Madison, Jackson and Swain Counties 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.

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

        In June 2004 the Company entered into a new five-year revolving committed credit facility totaling $125 million which replaced an existing committed credit facility.

4.     FINANCIAL INSTRUMENTS

        The Company follows the guidance required by SFAS 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 7 to the consolidated financial statements in the Company's 2003 Form 10-K.

        The Company utilizes hedging activities for natural gas purchases. Transaction fees and any realized gains or losses are recorded in deferred accounts for subsequent rate consideration. As of September 30, 2004 the Company had a deferred net gain of approximately $0.3 million.

        The Company also utilizes swap agreements to manage interest rate risk. At September 30, 2004 the estimated fair value of the Company's swaps totaled $1.8 million (gain) related to combined notional amounts of $29.9 million.

5.     COMMITMENTS AND CONTINGENCIES

        The Company is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. The Company'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. The Company 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 will be recoverable through gas rates.

6.     SEGMENT OF BUSINESS INFORMATION

        Gas Distribution is the Company's only reportable segment. Gas Distribution uses operating income to measure profitability. Intersegment revenues were not significant.

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Disclosure of Reportable Segments
(Millions of dollars)

Three Months Ended September 30,	2004							2003
	External Revenue		Operating Income (Loss)			Segment Assets		External Revenue		Operating Income (Loss)			Segment Assets
Gas Distribution	$	53	$	(6	)	$	994	$	59	$	(8	)	$	997
All Other		—		n/a			27		—		n/a			28
Adjustments/Eliminations		—		—			72		—		—			67
Consolidated Total	$	53	$	(6	)	$	1,093	$	59	$	(8	)	$	1,092

Nine Months Ended September 30,	2004						2003
	External Revenue		Operating Income		Segment Assets		External Revenue		Operating Income		Segment Assets
Gas Distribution	$	348	$	32	$	994	$	344	$	35	$	997
All Other		—		n/a		27		—		n/a		28
Adjustments/Eliminations		—		—		72		—		—		67
Consolidated Total	$	348	$	32	$	1,093	$	344	$	35	$	1,092

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Item 2.    Management's Narrative Analysis of Results of Operations.

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

        The following discussion should be read in conjunction with Management's Narrative Analysis of Results of Operations appearing in Public Service Company of North Carolina, Incorporated's (together with its consolidated subsidiaries, PSNC Energy) Annual Report on Form 10-K for the year ended December 31, 2003.

        Statements included in this narrative analysis (or elsewhere in this quarterly report) which are not statements of historical fact are intended to be, and are hereby identified as, "forward-looking statements" for purposes of the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following: (1) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) regulatory actions or changes in the utility regulatory environment, (3) current and future litigation, (4) changes in the economy, especially in PSNC Energy's service territory, (5) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (6) growth opportunities, (7) the results of financing efforts, (8) changes in PSNC Energy's accounting policies, (9) weather conditions, especially in areas served by PSNC Energy, (10) performance of SCANA Corporation's (SCANA) pension plan assets and the impact on PSNC Energy's results of operations, (11) inflation, (12) changes in environmental regulations and (13) the other risks and uncertainties described from time to time in PSNC Energy's periodic reports filed with the United States Securities and Exchange Commission. PSNC Energy disclaims any obligation to update any forward-looking statements.

Net Income and Distributions/Dividends

        Net income for the nine months ended September 30, 2004 decreased $3.2 million compared to the same period in 2003 primarily due to decreased margin of $1.6 million, higher operating expenses of $1.4 million and lower other income of $2.2 million, partially offset by lower income taxes of $1.9 million.

        The nature of PSNC Energy's business is seasonal. The quarters ending June 30 and September 30 are generally PSNC Energy's least profitable quarters due to decreased demand for natural gas related to space heating requirements.

        PSNC Energy's Board of Directors has authorized the following distributions/dividends on common stock held by SCANA during 2004:

Declaration Date	Amount		Quarter Ended	Payment Date
February 19, 2004	$	4.0 million	March 31, 2004	April 1, 2004
April 29, 2004	$	3.5 million	June 30, 2004	July 1, 2004
July 29, 2004	$	3.0 million	September 30, 2004	October 1, 2004
October 29, 2004	$	3.5 million	December 31, 2004	January 1, 2005

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Gas Distribution

        Gas distribution is comprised of the local distribution operations of PSNC Energy. Changes in the gas distribution sales margins were as follows:

		Nine Months Ended September 30,
Millions of dollars
		2004		Change		2003
Operating revenues		$	347.9	1.1	%	$	344.0
Less: Gas purchased for resale			226.1	2.5	%		220.6
	Margin	$	121.8	(1.3	)%	$	123.4

        Gas distribution sales margin for the nine months ended September 30, 2004 decreased primarily due to a decline in customer usage per degree-day of approximately $4.0 million, partially offset by customer growth and consumption of approximately $2.3 million.

Operation and Maintenance Expenses

        Operation and maintenance expenses increased $1.4 million for the nine months ended September 30, 2004 compared to the same period in 2003 primarily due to increased labor and benefits costs of $1.9 million and increased administrative and general business expenses of $1.2 million, partially offset by a decrease of $1.7 million in bad debt expense.

Other Income

        Other income decreased $2.2 million compared to the same period in 2003 primarily due to a $1.0 million loss recognized on the sale of PSNC Energy's former corporate headquarters in Gastonia, North Carolina and decreased interest income of $0.7 million on amounts under-collected from customers through the operation of the Rider D mechanism. This mechanism allows PSNC Energy to recover all prudently incurred gas costs.

Income Taxes

        Income taxes changed primarily as a result of changes in operating and other income.

Capital Expansion Program and Liquidity Matters

        PSNC Energy's capital expansion program includes the construction of lines, systems and facilities and the purchase of related equipment. PSNC Energy's 2004 construction budget is approximately $51 million, compared to actual construction expenditures through September 30, 2004 of $40.4 million. PSNC Energy's ratio of earnings to fixed charges for the 12 months ended September 30, 2004 was 3.13.

        In June 2004 PSNC Energy entered into a new five-year revolving committed credit facility totaling $125 million which replaced an existing committed credit facility. At September 30, 2004 PSNC Energy had $19.1 million in outstanding short-term borrowings at a weighted average interest rate of 1.87% and unused lines of credit of $125 million.

Item 4.    Controls and Procedures

        As of September 30, 2004 an evaluation was performed under the supervision and with the participation of PSNC Energy's management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of PSNC Energy's disclosure controls and procedures. Based on that evaluation, PSNC Energy's management, including the CEO and CFO, concluded that as of September 30, 2004 PSNC Energy's disclosure controls and procedures were effective. There has been no change in PSNC Energy's internal control over financial reporting during the quarter ended September 30, 2004 that has materially affected or is reasonably likely to materially affect PSNC Energy's internal control over financial reporting.

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PART II.    OTHER INFORMATION

Item 1.    Legal Proceedings

        On October 18, 2004 South Carolina Electric & Gas Company (SCE&G) announced that it had entered into a stipulation and settlement agreement with the Staff of the Public Service Commission of South Carolina (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 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 current 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.

        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

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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 1999 an unsuccessful bidder for the purchase of certain propane gas assets of SCANA Corporation (SCANA) filed suit against SCANA in Circuit Court, seeking unspecified damages. The 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 the Circuit Court and the case was sent to the jury. On October 21, 2004, the jury issued its verdict on this matter against SCANA 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 SCANA's interpretation that the damages awarded with respect to certain causes of action are overlapping. Therefore, it is SCANA'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, SCANA 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, SCANA recorded a pre-tax charge to earnings in the third quarter of 2004 of $18 million, $11 million after-tax, or 10 cents per share, which is SCANA's reasonable estimate of the loss that is probable if the final judgment is consistent with the jury verdict.

        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 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.

        Each of SCANA, SCE&G and PSNC Energy are engaged in various claims and litigation incidental to their business operations which management anticipates will be resolved without material loss. The status of matters previously disclosed in their respective Annual Reports on Form 10-K for 2003 have not changed significantly unless noted above.

Items 2, 3, 4, and 5 are not applicable.

Item 6.    Exhibits and Reports on Form 8-K

A.    Exhibits

SCANA Corporation, South Carolina Electric & Gas Company and Public Service Company of North Carolina, Incorporated:

Exhibits filed with this Quarterly Report on Form 10-Q are listed in the following Exhibit Index. Certain of such exhibits which have heretofore been filed with the Securities and Exchange Commission and which are designated by reference to their exhibit numbers in prior filings are hereby incorporated herein by reference and made a part hereof.

As permitted under Item 601(b)(4)(iii) of Regulation S-K, instruments defining the rights of holders of long-term debt of less than 10% of the total consolidated assets of SCANA, for itself and its subsidiaries, of SCE&G, for itself and its consolidated affiliates, and of PSNC Energy, for itself and its subsidiaries, have been omitted and SCANA, SCE&G and PSNC Energy agree to furnish a copy of such instruments to the Commission upon request.

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B. Reports on Form 8-K during the third quarter 2004 were as follows:

SCANA Corporation:
Date of report: July 23, 2004
Items reported: Items 7 & 12

South Carolina Electric & Gas Company:
Date of report: July 23, 2004
Items reported: Items 7 & 12

Public Service Company of North Carolina, Incorporated:
Date of report: July 23, 2004
Items reported: Items 7 & 12

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SIGNATURES

        Pursuant to the requirements of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. The signature of each registrant shall be deemed to relate only to matters having reference to such registrant and any subsidiaries thereof.

	SCANA CORPORATION SOUTH CAROLINA ELECTRIC & GAS COMPANY PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED (Registrants)
November 9, 2004	By:	/s/  JAMES E. SWAN, IV      James E. Swan, IV Controller (Principal accounting officer)

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EXHIBIT INDEX

        Applicable to Form 10-Q of

Exhibit No.	SCANA	SCE&G	PSNC Energy	Description
3.01	X			Restated Articles of Incorporation of SCANA Corporation as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference herein)
3.02	X			Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. 33-62421 and incorporated by reference herein)
3.03		X		Restated Articles of Incorporation of South Carolina Electric & Gas Company, as adopted on May 3, 2001 (Filed as Exhibit 3.01 to Registration Statement No. 333-65460 and incorporated by reference herein)
3.04		X		Articles of Amendment effective as of the dates indicated below and filed as exhibits to the Registration Statements set forth below and are incorporated by reference herein
				May 22, 2001	Exhibit 3.02	to Registration No. 333-65460
				June 14, 2001	Exhibit 3.04	to Registration No. 333-65460
				August 30, 2001	Exhibit 3.05	to Registration No. 333-101449
				March 13, 2002	Exhibit 3.06	to Registration No. 333-101449
				May 9, 2002	Exhibit 3.07	to Registration No. 333-101449
				June 4, 2002	Exhibit 3.08	to Registration No. 333-101449
				August 12, 2002	Exhibit 3.09	to Registration No. 333-101449
				March 13, 2003	Exhibit 3.03	to Registration No. 333-108760
				May 22, 2003	Exhibit 3.04	to Registration No. 333-108760
				June 18, 2003	Exhibit 3.05	to Registration No. 333-108760
				August 7, 2003	Exhibit 3.06	to Registration No. 333-108760
				May 18, 2004	Exhibit 3.05	to Form 10-Q for the quarter ended June 30, 2004
				June 18, 2004	Exhibit 3.06	to Form 10-Q for the quarter ended June 30, 2004
3.05		X		Articles of Amendment dated August 12, 2004 (Filed herewith)
3.06		X		Articles of Correction filed on June 1, 2001 correcting May 22, 2001 Articles of Amendment (Filed as Exhibit 3.03 to Registration Statement No. 333-65460 and incorporated by reference herein)
3.07		X		Articles of Correction filed on February 17, 2004 correcting the Articles of Amendment dated as indicated below and filed as exhibits to Form 10-K for the year ended December 31, 2003 and are incorporated by reference herein
				May 3, 2001	Exhibit 3.06
				May 22, 2001	Exhibit 3.07
				June 14, 2001	Exhibit 3.08
				August 30, 2001	Exhibit 3.09
				March 13, 2002	Exhibit 3.10
				May 9, 2002	Exhibit 3.11
				June 4, 2002	Exhibit 3.12
				August 12, 2002	Exhibit 3.13
				March 13, 2003	Exhibit 3.14
				May 22, 2003	Exhibit 3.15
				June 18, 2003	Exhibit 3.16
				August 7, 2003	Exhibit 3.17
3.08	X			By-Laws of SCANA as revised and amended on December 13, 2000 (Filed as Exhibit 3.01 to Registration Statement No. 333-68266 and incorporated by reference herein)
3.09		X		By-Laws of SCE&G as revised and amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460 and incorporated by reference herein)
3.10			X	By-Laws of PSNC Energy as revised and amended on February 22, 2001 (Filed as Exhibit 3.01 to Registration Statement No. 333-68516 and incorporated by reference herein)

72

4.01	X	X	Articles of Exchange of South Carolina Electric & Gas Company and SCANA Corporation (Filed as Exhibit 4-A to Post-Effective Amendment No. 1 to Registration Statement No. 2-90438 and incorporated by reference herein)
4.02	X		Indenture dated as of November 1, 1989 between SCANA Corporation and The Bank of New York, as Trustee (Filed as Exhibit 4-A to Registration No. 33-32107 and incorporated by reference herein)
4.03	X	X	Indenture dated as of January 1, 1945, between the South Carolina Power Company and Central Hanover Bank and Trust Company, as Trustee, as supplemented by three Supplemental Indentures dated respectively as of May 1, 1946, May 1, 1947 and July 1, 1949 (Filed as Exhibit 2-B to Registration Statement No. 2-26459 and incorporated by reference herein)
4.04	X	X	Fourth Supplemental Indenture dated as of April 1, 1950, to Indenture referred to in Exhibit 4.03, pursuant to which SCE&G assumed said Indenture (Exhibit 2-C to Registration Statement No. 2-26459 and incorporated by reference herein)
4.05	X	X	Fifth through Fifty-third Supplemental Indenture referred to in Exhibit 4.03 dated as of the dates indicated below and filed as exhibits to the Registration Statements set forth below and are incorporated by reference herein
			December 1, 1950	Exhibit 2-D	to Registration No. 2-26459
			July 1, 1951	Exhibit 2-E	to Registration No. 2-26459
			June 1, 1953	Exhibit 2-F	to Registration No. 2-26459
			June 1, 1955	Exhibit 2-G	to Registration No. 2-26459
			November 1, 1957	Exhibit 2-H	to Registration No. 2-26459
			September 1, 1958	Exhibit 2-I	to Registration No. 2-26459
			September 1, 1960	Exhibit 2-J	to Registration No. 2-26459
			June 1, 1961	Exhibit 2-K	to Registration No. 2-26459
			December 1, 1965	Exhibit 2-L	to Registration No. 2-26459
			June 1, 1966	Exhibit 2-M	to Registration No. 2-26459
			June 1, 1967	Exhibit 2-N	to Registration No. 2-29693
			September 1, 1968	Exhibit 4-O	to Registration No. 2-31569
			June 1, 1969	Exhibit 4-C	to Registration No. 33-38580
			December 1, 1969	Exhibit 4-O	to Registration No. 2-35388
			June 1, 1970	Exhibit 4-R	to Registration No. 2-37363
			March 1, 1971	Exhibit 2-B-17	to Registration No. 2-40324
			January 1, 1972	Exhibit 2-B	to Registration No. 33-38580
			July 1, 1974	Exhibit 2-A-19	to Registration No. 2-51291
			May 1, 1975	Exhibit 4-C	to Registration No. 33-38580
			July 1, 1975	Exhibit 2-B-21	to Registration No. 2-53908
			February 1, 1976	Exhibit 2-B-22	to Registration No. 2-55304
			December 1, 1976	Exhibit 2-B-23	to Registration No. 2-57936
			March 1, 1977	Exhibit 2-B-24	to Registration No. 2-58662
			May 1, 1977	Exhibit 4-C	to Registration No. 33-38580
			February 1, 1978	Exhibit 4-C	to Registration No. 33-38580
			June 1, 1978	Exhibit 2-A-3	to Registration No. 2-61653
			April 1, 1979	Exhibit 4-C	to Registration No. 33-38580
			June 1, 1979	Exhibit 2-A-3	to Registration No. 33-38580
			April 1, 1980	Exhibit 4-C	to Registration No. 33-38580
			June 1, 1980	Exhibit 4-C	to Registration No. 33-38580
			December 1, 1980	Exhibit 4-C	to Registration No. 33-38580
			April 1, 1981	Exhibit 4-D	to Registration No. 33-38580
			June 1, 1981	Exhibit 4-D	to Registration No. 33-49421
			March 1, 1982	Exhibit 4-D	to Registration No. 2-73321
			April 15, 1982	Exhibit 4-D	to Registration No. 33-49421
			May 1, 1982	Exhibit 4-D	to Registration No. 33-49421
			December 1, 1984	Exhibit 4-D	to Registration No. 33-49421
			December 1, 1985	Exhibit 4-D	to Registration No. 33-49421
			June 1, 1986	Exhibit 4-D	to Registration No. 33-49421

73

				February 1, 1987	Exhibit 4-D	to Registration No. 33-49421
				September 1, 1987	Exhibit 4-D	to Registration No. 33-49421
				January 1, 1989	Exhibit 4-D	to Registration No. 33-49421
				January 1, 1991	Exhibit 4-D	to Registration No. 33-49421
				July 15, 1991	Exhibit 4-D	to Registration No. 33-49421
				August 15, 1991	Exhibit 4-D	to Registration No. 33-49421
				April 1, 1993	Exhibit 4-E	to Registration No. 33-49421
				July 1, 1993	Exhibit 4-D	to Registration No. 33-49421
				May 1, 1999	Exhibit 4.04	to Registration No. 333-86387
4.06	X	X		Indenture dated as of April 1, 1993 from South Carolina Electric & Gas Company to NationsBank of Georgia, National Association (Filed as Exhibit 4-F to Registration Statement No. 33-49421 and incorporated by reference herein)
4.07	X	X		First Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421 and incorporated by reference herein)
4.08	X	X		Second Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955 and incorporated by reference herein)
4.09	X		X	Indenture dated as of January 1, 1996 between PSNC and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.08 to Registration Statement No. 333-45206 and incorporated by reference herein)
4.10	X		X	First through Fourth Supplemental Indenture referred to in Exhibit 4.09 dated as of the dates indicated below and filed as exhibits to the Registration Statements whose file numbers are set forth below and are incorporated by reference herein
				January 1, 1996	Exhibit 4.09	to Registration No. 333-45206
				December 15, 1996	Exhibit 4.10	to Registration No. 333-45206
				February 10, 2000	Exhibit 4.11	to Registration No. 333-45206
				February 12, 2001	Exhibit 4.05	to Registration No. 333-68516
4.11	X		X	PSNC $150 million medium-term note issued February 16, 2001 (Filed as Exhibit 4.06 to Registration Statement No. 333-68516 and incorporated by reference herein)
*10.01	X	X	X	SCANA Executive Deferred Compensation Plan as amended February 20, 2003 (Filed as Exhibit 10.01 to Form 10-Q for the quarter ended June 30, 2003 and incorporated by reference herein)
*10.02	X	X	X	SCANA Director Compensation and Deferral Plan as amended January 1, 2001 (Filed as Exhibit 4.03 to Registration Statement No. 333-18973 and incorporated by reference herein)
*10.03	X	X	X	Amendment to SCANA Director Compensation and Deferral Plan adopted April 29, 2004 (Filed as Exhibit 10.03 to Form 10-Q for the quarter ended March 31, 2004 and incorporated by reference herein)
*10.04	X	X	X	SCANA Supplementary Executive Retirement Plan as amended July 1, 2001 (Filed as Exhibit 10.02 to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein)
*10.05	X	X	X	SCANA Key Executive Severance Benefits Plan as amended July 1, 2001 (Filed as Exhibit 10.03 to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein)
*10.06	X	X	X	SCANA Supplementary Key Severance Benefits Plan as amended July 1, 2001 (Filed as Exhibit 10.03a to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein)
*10.07	X	X	X	SCANA Long-Term Equity Compensation Plan dated January 2000 (Filed as Exhibit 4.04 to Registration Statement No. 333-37398 and incorporated by reference herein)

74

*10.08	X	X	X	Amendment to SCANA Long-Term Equity Compensation Plan adopted April 29, 2004 (Filed as Exhibit 10.08 to Form 10-Q for the quarter ended March 31, 2004 and incorporated by reference herein)
*10.09	X	X	X	Description of SCANA Whole Life Option (Filed as Exhibit 10-F to Form 10-K for the year ended December 31, 1991, under cover of Form SE, File No. 1-8809 and incorporated by reference herein)
*10.10	X	X	X	Description of SCANA Corporation Executive Annual Incentive Plan (Filed as Exhibit 10-G to Form 10-K for the year ended December 31, 1991, under cover of Form SE, File No. 1-8809 and incorporated by reference herein)
10.11			X	Operating Agreement of Pine Needle LNG Company, LLC dated August 8, 1995 (Filed as Exhibit 10.01 to Registration Statement No. 333-45206 and incorporated by reference herein)
10.12			X	Amendment to Operating Agreement of Pine Needle LNG Company, LLC dated October 1, 1995 (Filed as Exhibit 10.02 to Registration Statement No. 333-45206 and incorporated by reference herein)
10.13			X	Amended Operating Agreement of Cardinal Extension Company, LLC dated December 19, 1996 (Filed as Exhibit 10.03 to Registration Statement No. 333-45206 and incorporated by reference herein)
10.14			X	Amended Construction, Operation and Maintenance Agreement by and between Cardinal Operating Company and Cardinal Extension Company, LLC dated December 19, 1996 (Filed as Exhibit 10.04 to Registration Statement No. 333-45206 and incorporated by reference herein)
10.15			X	Service Agreement between PSNC and SCANA Services, Inc., effective January 1, 2004 (Filed as Exhibit 10.15 to Form 10-Q for the quarter ended March 31, 2004 and incorporated by reference herein)
10.16		X		Service Agreement between SCE&G and SCANA Services, Inc., effective January 1, 2004 (Filed as Exhibit 10.16 to Form 10-Q for the quarter ended March 31, 2004 and incorporated by reference herein)
31.01	X			Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.02	X			Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
31.03		X		Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.04		X		Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
31.05			X	Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.06			X	Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
32.01	X			Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.02	X			Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
31.03		X		Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
31.04		X		Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
31.05			X	Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
31.06			X	Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

*

Management Contract or Compensatory Plan or Arrangement

75

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INDEX
SCANA CORPORATION FINANCIAL SECTION
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures

SOUTH CAROLINA ELECTRIC & GAS COMPANY FINANCIAL SECTION

Item 1. Financial Statements

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED FINANCIAL SECTION

Item 1. Financial Statements.

Item 2. Management's Narrative Analysis of Results of Operations.
Item 4. Controls and Procedures

PART II. OTHER INFORMATION

Item 1. Legal Proceedings
Item 6. Exhibits and Reports on Form 8-K

SIGNATURES
EXHIBIT INDEX