QuickLinks-- Click here to rapidly navigate through this document

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

FORM 10-Q (X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2003 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition Period from to Commission Registrant, State of Incorporation, I.R.S. Employer File Number Address and Telephone Number Identification No. 1-8809 SCANA Corporation 57-0784499 (a South Carolina Corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000 1-3375 South Carolina Electric & Gas Company 57-0248695 (a South Carolina Corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000 1-11429 Public Service Company of North Carolina, Incorporated 56-2128483 (a South Carolina Corporation) 1426 Main Street, Columbia, South Carolina 29201

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 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, Address and Telephone Number	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 Xý Noo South Carolina Electric & Gas Company Yes Xý Noo Public Service Company of North Carolina, Incorporated Yes Xý Noo.

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Description of Shares Outstanding Registrant Common Stock at October 31, ---------- ------------ -------------- 2003 SCANA Corporation Without Par Value 110,748,408 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)

Registrant	Description of Common Stock	Shares Outstanding at April 30, 2004
SCANA Corporation	Without Par Value	111,114,644
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): Held beneficially and of record by SCANA Corporation.

This combined Form 10-Q is separately filed by SCANA Corporation, South Carolina Electric & Gas Company and Public Service Company of North Carolina, Incorporated. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies.

Public Service Company of North Carolina, Incorporated meets the conditions set forth in General Instruction ~~H (1)~~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

~~INDEX~~
		Page
PART I. FINANCIAL INFORMATION
SCANA Corporation Financial ~~Section....................................................................................~~ Section		3
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of ~~September 30, 2003~~March 31, 2004 and December 31, ~~2002 ....................~~ 2003	4
	Condensed Consolidated Statements of ~~Operations~~Income for the Periods Ended ~~September 30,~~March 31, 2004 and 2003 ~~and 2002........~~	6
	Condensed Consolidated Statements of Cash Flows for the Periods Ended ~~September 30,~~March 31, 2004 and 2003 ~~and 2002........~~	7
	Condensed Consolidated Statements of Comprehensive Income ~~(Loss)~~ for the Periods Ended ~~September 30,~~March 31, 2004 and 2003 ~~and 2002......................................................................~~	8
	Notes to Condensed Consolidated Financial ~~Statements.....................................................~~ Statements	9
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of ~~Operations........................ 22~~ Operations	19
Item 3.	Quantitative and Qualitative Disclosures About Market ~~Risk................................................... 32~~ Risk	26
Item 4.	Controls and ~~Procedures...................................................................................... 34~~ Procedures	27
South Carolina Electric & Gas Company Financial ~~Section................................................................ 35~~ Section		28
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of ~~September 30, 2003~~March 31, 2004 and December 31, ~~2002 .................... 36~~ 2003	29
	Condensed Consolidated Statements of Income for the Periods Ended ~~September 30,~~March 31, 2004 and 2003 ~~and 2002............ 38~~	31
	Condensed Consolidated Statements of Cash Flows for the Periods Ended ~~September 30,~~March 31, 2004 and 2003 ~~and 2002........ 39~~	32
	Notes to Condensed Consolidated Financial ~~Statements..................................................... 40~~ Statements	33
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of ~~Operations......................... 47~~ Operations	40
Item 3.	Quantitative and Qualitative Disclosures About Market ~~Risk.................................................... 53~~ Risk	46
Item 4.	Controls and ~~Procedures....................................................................................... 54~~ Procedures	46
Public Service Company of North Carolina, Incorporated Financial ~~Section............................................... 55~~ Section		47
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of ~~September 30, 2003~~March 31, 2004 and December 31, ~~2002 .................... 56~~ 2003	48
	Condensed Consolidated Statements of ~~Operations~~Income for the Periods Ended ~~September 30,~~March 31, 2004 and 2003 ~~and 2002........ 57~~	49
	Condensed Consolidated Statements of Cash Flows for the Periods Ended ~~September 30,~~March 31, 2004 and 2003 ~~and 2002........ 58~~	50
	Notes to Condensed Consolidated Financial ~~Statements..................................................... 59~~ Statements	51
Item 2.	Management's Narrative Analysis of Results of ~~Operations...................................................... 64~~ Operations	54
Item 4.	Controls and ~~Procedures....................................................................................... 66~~ Procedures	55
PART II. OTHER INFORMATION
Item 1.	Legal ~~Proceedings............................................................................................. 67~~ Proceedings	56
Item 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities	56
Item 6.	Exhibits and Reports on Form 8-K.............................................................................. 69 Signatures............................................................................................................. 70 8-K	56
Signatures		58
Exhibit Index.......................................................................................................... 71 Certifications Required by Rule 13a-14 ................................................................................ 76 Certifications Pursuant to 18 U.S.C. Section 1350...................................................................... 82 Index		59

SCANA CORPORATION
FINANCIAL SECTION
PART I. FINANCIAL INFORMATION Item 1. Financial Statements SCANA CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - ------------------------------------------------------------------------------- ------------------ ------------------ September 30, December 31, Millions of dollars 2003 2002 - ------------------------------------------------------------------------------- ------------------ ------------------ Assets Utility Plant: Electric $5,416 $5,228 Gas 1,650 1,593 Other 181 184 - ------------------------------------------------------------------------------- ------------------ ------------------ Total 7,247 7,005 Accumulated depreciation and amortization (2,606) (2,476) - ------------------------------------------------------------------------------- ------------------ ------------------ Total 4,641 4,529 Construction work in progress 994 677 Nuclear fuel, net of accumulated amortization 41 38 Acquisition adjustments, net of accumulated amortization 230 230 - ------------------------------------------------------------------------------- ------------------ ------------------ Utility Plant, Net 5,906 5,474 - ------------------------------------------------------------------------------- ------------------ ------------------ Nonutility Property, Net of Accumulated Depreciation 93 95 Investments 222 231 - ------------------------------------------------------------------------------- ------------------ ------------------ - ------------------------------------------------------------------------------- ------------------ ------------------ Nonutility Property and Investments, Net 315 326 - ------------------------------------------------------------------------------- ------------------ ------------------ - ------------------------------------------------------------------------------- ------------------ ------------------ Current Assets: Cash and temporary investments 80 374 Receivables, net of allowance for uncollectible accounts of $15 and $17 358 478 Receivables - affiliated companies 15 8 Inventories (at average cost): Fuel 169 166 Materials and supplies 60 61 Emission allowances 7 10 Prepayments 36 40 Deferred income taxes, net 4 - - ------------------------------------------------------------------------------- ------------------ ------------------ Total Current Assets 729 1,137 - ------------------------------------------------------------------------------- ------------------ ------------------ Deferred Debits: Environmental 21 27 Nuclear plant decommissioning - 87 Assets held in trust, net-nuclear decommissioning 35 - Pension asset, net 269 265 Other regulatory assets 331 292 Other 182 138 - ------------------------------------------------------------------------------- ------------------ ------------------ Total Deferred Debits 838 809 - ------------------------------------------------------------------------------- ------------------ ------------------ Total $7,788 $7,746 =============================================================================== ================== ================== - ------------------------------------------------------------------------------------ ------------------- ----------------- September 30, December 31, Millions of dollars 2003 2002 - ------------------------------------------------------------------------------------ ------------------- ----------------- Capitalization and Liabilities Stockholders' Investment: Common equity $2,306 $2,177 Preferred stock (Not subject to purchase or sinking funds) 106 106 - ------------------------------------------------------------------------------------ ------------------- ----------------- Total Stockholders' Investment 2,412 2,283 Preferred Stock, net (Subject to purchase or sinking funds) 9 9 SCE&G-Obligated Mandatorily Redeemable Preferred Securities of SCE&G's Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount of 7.55% Junior Subordinated Debentures of SCE&G - 50 Long-Term Debt, net 2,852 2,834 - ------------------------------------------------------------------------------------ ------------------- ----------------- Total Capitalization 5,273 5,176 - ------------------------------------------------------------------------------------ ------------------- ----------------- Current Liabilities: Short-term borrowings 242 209 Current portion of long-term debt 402 413 Accounts payable 201 354 Accounts payable - affiliated companies 14 8 Customer deposits 43 39 Taxes accrued 72 78 Interest accrued 52 52 Dividends declared 41 39 Deferred income taxes, net - 4 Other 51 77 - ------------------------------------------------------------------------------------ ------------------- ----------------- Total Current Liabilities 1,118 1,273 - ------------------------------------------------------------------------------------ ------------------- ----------------- Deferred Credits: Deferred income taxes, net 782 747 Deferred investment tax credits 119 118 Reserve for nuclear plant decommissioning - 87 Asset retirement obligation - nuclear plant 116 - Postretirement benefits 133 131 Regulatory liabilities 144 114 Other 103 100 - ------------------------------------------------------------------------------------ ------------------- ----------------- Total Deferred Credits 1,397 1,297 - ------------------------------------------------------------------------------------ ------------------- ----------------- Total $7,788 $7,746 ==================================================================================== =================== ================= See Notes to Condensed Consolidated Financial Statements. SCANA CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - -------------------------------------------------------------------- --------------------------- --------------------------- Three Months Ended Nine Months Ended September 30, September 30, Millions of dollars, except per share amounts 2003 2002 2003 2002 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Operating Revenues: Electric $429 $424 $1,121 $1,075 Gas - regulated 155 136 775 587 Gas - nonregulated 167 134 650 503 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Total Operating Revenues 751 694 2,546 2,165 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Operating Expenses: Fuel used in electric generation 97 105 258 271 Purchased power 13 7 39 29 Gas purchased for resale 262 215 1,127 828 Other operation and maintenance 135 126 420 383 Depreciation and amortization 60 55 180 163 Other taxes 34 32 104 95 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Total Operating Expenses 601 540 2,128 1,769 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Operating Income 150 154 418 396 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Other Income: Other income, including allowance for equity funds used during construction of $6, $6, $15 and $18 16 17 48 54 Gain on sale of investments and assets 3 - 60 31 Impairment of investments - - (7) (255) - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Total Other Income (Expense) 19 17 101 (170) - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Income Before Interest Charges, Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change 169 171 519 226 Interest Charges, Net of Allowance for Borrowed Funds Used During Construction of $3, $3, $9 and $10 48 49 149 151 Dividend Requirement of SCE&G - Obligated Mandatorily Redeemable Preferred Securities - 1 2 3 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Income Before Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change 121 121 368 72 Income Tax Expense 35 41 120 20 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Income Before Preferred Stock Dividends and Cumulative Effect of Accounting Change 86 80 248 52 Cash Dividends on Preferred Stock of Subsidiary (At stated rates) 2 2 6 6 - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Income Before Cumulative Effect of Accounting Change 84 78 242 46 Cumulative Effect of Accounting Change, net of taxes - - - (230) - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Net Income (Loss) $84 $78 $242 $(184) ==================================================================== =============== =========== ============ ============== ==================================================================== =============== =========== ============ ============== Basic and Diluted Earnings Per Share of Common Stock: Before Cumulative Effect of Accounting Change $.76 $.74 $2.18 $.44 Cumulative Effect of Accounting Change, net of taxes - - - (2.20) - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- - -------------------------------------------------------------------- --------------- ----------- ------------ -------------- Basic and Diluted Earnings (Loss) Per Share $.76 $.74 $2.18 $(1.76) ==================================================================== =============== =========== ============ ============== ==================================================================== =============== =========== ============ ============== Weighted Average Shares Outstanding (millions) 110.9 104.7 110.9 104.7 See Notes to Condensed Consolidated Financial Statements. SCANA CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - --------------------------------------------------------------------------------------- ---------------------------------- Nine Months Ended September 30, Millions of dollars 2003 2002 - --------------------------------------------------------------------------------------- ------------------ --------------- Cash Flows From Operating Activities: Net income (loss) $242 $(184) Adjustments to reconcile net income (loss) to net cash provided from operating activities: Cumulative effect of accounting change, net of taxes - 230 Depreciation and amortization 188 172 Amortization of nuclear fuel 18 14 Gain on sale of investments and assets (60) (31) Hedging activities (4) 45 Investment impairments 7 255 Allowance for funds used during construction (24) (28) Over (under) collection, fuel adjustment clauses 18 (39) Changes in certain assets and liabilities: (Increase) decrease in receivables, net 113 82 (Increase) decrease in inventories 1 (10) (Increase) decrease in prepayments 4 (1) (Increase) decrease in pension asset (4) (20) (Increase) decrease in other regulatory assets (20) - Increase (decrease) in deferred income taxes, net 27 (138) Increase (decrease) in regulatory liabilities 38 32 Increase (decrease) in postretirement benefits obligations 2 7 Increase (decrease) in accounts payable (147) (62) Increase (decrease) in taxes accrued (6) (18) Increase (decrease) in interest accrued - 9 Changes in other assets (5) 12 Changes in other liabilities 11 20 - --------------------------------------------------------------------------------------- ------------------ --------------- Net Cash Provided From Operating Activities 399 347 - --------------------------------------------------------------------------------------- ------------------ --------------- Cash Flows From Investing Activities: Utility property additions and construction expenditures, net of AFC (558) (424) Proceeds from sale of investments and assets 69 335 Increase in nonutility property (6) (12) Investments in affiliates (11) (25) - --------------------------------------------------------------------------------------- ------------------ --------------- - --------------------------------------------------------------------------------------- ------------------ --------------- Net Cash Used For Investing Activities (506) (126) - --------------------------------------------------------------------------------------- ------------------ --------------- Cash Flows From Financing Activities: Proceeds: Issuance of First Mortgage Bonds 495 295 Issuance of Pollution Control Bonds 36 - Issuance of notes and loans - 497 Issuance of common stock upon exercise of stock options 4 - Repayments: Mortgage bonds (250) (104) Notes and loans (271) (907) Pollution Control Bonds (43) - Retirement of preferred stock - (1) SCE&G Trust I Preferred Securities (50) - Payment of deferred financing costs (22) - Dividends and distributions: Common stock (113) (100) Preferred stock (6) (6) Short-term borrowings, net 33 84 - --------------------------------------------------------------------------------------- ------------------ --------------- Net Cash Used For Financing Activities (187) (242) - --------------------------------------------------------------------------------------- ------------------ --------------- Net Decrease In Cash and Temporary Investments (294) (21) Cash and Temporary Investments, January 1 374 192 - --------------------------------------------------------------------------------------- ------------------ --------------- Cash and Temporary Investments, September 30 $80 $171 ======================================================================================= ================== =============== Supplemental Cash Flow Information: Cash paid for - Interest (net of capitalized interest of $9 and $10) $149 $142 - Income taxes 63 131 Noncash Investing and Financing Activities: Unrealized gain on securities available for sale, net of tax 1 17 See Notes to Condensed Consolidated Financial Statements. SCANA CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - ----------------------------------------------------------------------- ----------------------- ----------------------- Three Months Ended Nine Months Ended September 30, September 30, Millions of dollars 2003 2002 2003 2002 - ----------------------------------------------------------------------- ----------- ----------- ---------- ------------ - ----------------------------------------------------------------------- ----------- ----------- ---------- ------------ Net Income (Loss) $84 $78 $242 $(184) Other Comprehensive Income (Loss), net of tax: Unrealized gains (losses) on securities available for sale 1 (12) 1 17 Unrealized gains (losses) on hedging activities (2) 1 (4) 28 - ----------------------------------------------------------------------- ----------- ----------- ---------- ------------ Total Comprehensive Income (Loss) (1) $83 $67 $239 $(139) ======================================================================= =========== =========== ========== ============ (1) Accumulated other comprehensive income (loss) of the Company totaled $(1.1) million and $1.0 million as of September 30, 2003 and December 31, 2002, respectively.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

Millions of dollars			March 31, 2004			December 31, 2003
Assets
Utility Plant:
	Electric		$	5,616		$	5,558
	Gas			1,691			1,687
	Common			196			193

	Total			7,503			7,438
	Accumulated depreciation and amortization			(2,316	)		(2,280	)

	Total			5,187			5,158
	Construction work in progress			1,035			987
	Nuclear fuel, net of accumulated amortization			36			42
	Acquisition adjustments, net of accumulated amortization			230			230

	Utility Plant, Net			6,488			6,417

Nonutility Property, Net of Accumulated Depreciation				93			96
Investments				168			178

	Nonutility Property and Investments, Net			261			274

Current Assets:
	Cash and temporary investments			218			117
	Receivables, net of allowance for uncollectible accounts of $23 and $16			494			503
	Receivables—affiliated companies			18			13
	Inventories (at average cost):
		Fuel		94			147
		Materials and supplies		62			60
		Emission allowances		13			6
	Prepayments			41			36
	Deferred income taxes, net			12			—

	Total Current Assets			952			882

Deferred Debits:
	Environmental			19			20
	Assets held in trust, net—nuclear decommissioning			46			44
	Pension asset, net			274			270
	Other regulatory assets			328			348
	Other			181			175

	Total Deferred Debits			848			857

Total			$	8,549		$	8,430

Millions of dollars		March 31, 2004		December 31, 2003
Capitalization and Liabilities
Shareholders' Investment:
	Common equity	$	2,370	$	2,306
	Preferred stock (Not subject to purchase or sinking funds)		106		106

	Total Shareholders' Investment		2,476		2,412
Preferred Stock, net (Subject to purchase or sinking funds)			9		9
Long-Term Debt, net			3,332		3,225

	Total Capitalization		5,817		5,646

Current Liabilities:
	Short-term borrowings		191		195
	Current portion of long-term debt		202		202
	Accounts payable		238		288
	Accounts payable—affiliated companies		16		12
	Customer deposits		45		43
	Taxes accrued		51		81
	Interest accrued		57		55
	Dividends declared		43		41
	Deferred income taxes, net		—		4
	Other		49		74

	Total Current Liabilities		892		995

Deferred Credits:
	Deferred income taxes, net		802		790
	Deferred investment tax credits		116		117
	Asset retirement obligation—nuclear plant		119		118
	Postretirement benefits		136		135
	Other regulatory liabilities		549		519
	Other		118		110

	Total Deferred Credits		1,840		1,789

Commitments and Contingencies			—		—

Total		$	8,549	$	8,430

See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

		Three Months Ended March 31,
Millions of dollars, except per share amounts		Three Months Ended March 31,
Millions of dollars, except per share amounts		2004		2003
Operating Revenues:
	Electric	$	380	$	336
	Gas—regulated		426		427
	Gas—nonregulated		330		306

	Total Operating Revenues		1,136		1,069

Operating Expenses:
	Fuel used in electric generation		95		81
	Purchased power		13		10
	Gas purchased for resale		577		571
	Other operation and maintenance		155		144
	Depreciation and amortization		63		60
	Other taxes		39		35

	Total Operating Expenses		942		901

Operating Income			194		168
Other Income, Including Allowance for Equity Funds Used During Construction of $6 and $5			14		16

Income Before Interest Charges, Income Taxes and Preferred Stock Dividends			208		184
Interest Charges, Net of Allowance for Borrowed Funds Used During Construction of $4 and $2			50		51
Dividend Requirement of SCE&G—Obligated Mandatorily Redeemable Preferred Securities			—		1

Income Before Income Taxes and Preferred Stock Dividends			158		132
Income Tax Expense			55		46

Income Before Preferred Stock Dividends			103		86
Cash Dividends on Preferred Stock of Subsidiary (At stated rates)			2		2

Net Income		$	101	$	84

Basic and Diluted Earnings Per Share of Common Stock		$	.91	$	.75
Weighted Average Shares Outstanding (millions)			110.9		110.8

See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

				Three Months Ended March 31,
Millions of dollars				Three Months Ended March 31,
Millions of dollars				2004			2003
Cash Flows From Operating Activities:
	Net income			$	101		$	84
	Adjustments to reconcile net income to net cash provided from operating activities:
		Depreciation and amortization			64			62
		Amortization of nuclear fuel			6			6
		Loss on sale of assets			1			—
		Hedging activities			(3	)		(3	)
		Allowance for funds used during construction			(10	)		(7	)
		Over collection, fuel adjustment clauses			42			16
		Changes in certain assets and liabilities:
			(Increase) decrease in receivables, net		4			(38	)
			(Increase) decrease in inventories		44			62
			(Increase) decrease in prepayments		(5	)		—
			(Increase) decrease in pension asset		(4	)		(1	)
			(Increase) decrease in other regulatory assets		1			(1	)
			Increase (decrease) in deferred income taxes, net		1			1
			Increase (decrease) in regulatory liabilities		3			9
			Increase (decrease) in postretirement benefits obligations		1			3
			Increase (decrease) in accounts payable		(46	)		10
			Increase (decrease) in taxes accrued		(30	)		(24	)
			Increase (decrease) in interest accrued		2			6
		Changes in other assets			4			(10	)
��		Changes in other liabilities			(13	)		(20	)

	Net Cash Provided From Operating Activities				163			155

Cash Flows From Investing Activities:
	Utility property additions and construction expenditures, net of AFC				(122	)		(171	)
	Increase in nonutility property				(4	)		(3	)
	Investments in affiliates				(3	)		(4	)

	Net Cash Used For Investing Activities				(129	)		(178	)

Cash Flows From Financing Activities:
	Proceeds:
		Issuance of First Mortgage Bonds			—			198
		Issuance of notes and loans			100			—
		Issuance of common stock upon exercise of stock options			15			—
	Repayments:
		Notes and loans			—			(60	)
		Repurchase of common stock			(4	)		—
	Dividends and distributions:
		Common stock			(38	)		(37	)
		Preferred stock			(2	)		(2	)
	Short-term borrowings, net				(4	)		(95	)

	Net Cash Provided From Financing Activities				67			4

Net Increase (Decrease) In Cash and Temporary Investments					101			(19	)
Cash and Temporary Investments, January 1					117			341

Cash and Temporary Investments, March 31				$	218		$	322

Supplemental Cash Flow Information:
	Cash paid for—Interest (net of capitalized interest of $4 and $2)			$	47		$	46
	—Income taxes				—			1
Noncash Investing and Financing Activities:
	Unrealized loss on securities available for sale, net of tax				(6	)		—

See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

		Three Months Ended March 31,
Millions of dollars		Three Months Ended March 31,
Millions of dollars		2004			2003
Net Income		$	101		$	84
Other Comprehensive Income (Loss), net of tax:
	Unrealized losses on securities available for sale		(6	)		—
	Unrealized losses on hedging activities		(2	)		(2	)

Total Comprehensive Income⁽¹⁾		$	93		$	82

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

See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ~~September 30, 2003~~
March 31, 2004
(Unaudited)

The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in SCANA Corporation's ~~(the~~(together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, ~~2002.~~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~~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, 2003,~~March 31, 2004, approximately ~~$352~~$347 million and ~~$144~~$549 million of regulatory assets (including environmental) and liabilities, respectively, as shown below. September 30, December 31, Millions of dollars 2003 2002 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Accumulated deferred income taxes, net $95 $95 Under-collections - electric fuelrespectively. Information relating to regulatory assets and gas cost adjustment clauses, net 40 61 Deferred environmental remediation costs 21 27 Asset retirement obligation - nuclear decommissioning 43 - Deferred non-conventional fuel tax benefits, net (59) (40) Storm damage reserve (36) (32) Franchise agreements 62 65 Other 42 29 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Total $208 $205 ================================================================================liabilities follows.

Millions of dollars	March 31, 2004			December 31, 2003
Accumulated deferred income taxes, net	$	109		$	110
Under-(over)-collections—electric fuel and gas cost adjustment clauses, net		(1	)		38
Deferred environmental remediation costs		19			20
Asset retirement obligation—nuclear decommissioning		47			48
Deferred non-conventional fuel tax benefits, net		(74	)		(67	)
Storm damage reserve		(34	)		(37	)
Franchise agreements		60			62
Non-legal asset retirement obligations		(353	)		(346	)
Other		25			21

Total	$	(202	)	$	(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-collections -~~

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

Deferred environmental remediation costs represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by the Company. Costs incurred at sites owned by South Carolina Electric & Gas Company (SCE&G) are being recovered through rates. Such costs, totaling approximately ~~$11.6~~$9.8 million, are expected to be fully recovered by the end of ~~2005.~~2009. A portion of the costs incurred at sites owned by ~~Public Service Company of North Carolina, Incorporated (PSNC Energy) is also being~~PSNC Energy has been recovered

through rates, and management believes the remaining costs of approximately ~~$7.5~~$6.8 million will be recoverable. Amounts incurred and deferred to date that are not currently being recovered through gas rates at PSNC Energy are approximately ~~$1.5~~$2.4 million. ~~(See Note 3.)~~

Asset retirement ~~obligation -~~ obligation—nuclear decommissioning represents the regulatory asset associated with the legal obligation ~~of decommissioning~~to decommission and ~~dismantling~~dismantle V. C. Summer Nuclear Station (Summer Station) as required inby SFAS 143, "Accounting for Asset Retirement Obligations." ~~(See Note 1B.)~~

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

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

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

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

The SCPSC and the NCUC (collectively, state commissions) have reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by ~~the SCPSC or the NCUC.~~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 ~~SCPSC or NCUC~~state commission approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company's results of operations, liquidity or financial position in the period the write-off would be recorded.

B. New Accounting Standards The Company adopted SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002. In connection with this implementation, the Company performed a valuation analysis of its investment in South Carolina Pipeline Corporation (SCPC) using a discounted cash flow analysis and of PSNC Energy using an independent appraisal. The analysis of the investment in PSNC Energy indicated that the carrying amount of PSNC Energy's acquisition adjustment exceeded its fair value by approximately $230 million, or a $2.20 per share. The resulting impairment charge is reflected on the Condensed Consolidated Statement of Operations as the cumulative effect of an accounting change. SFAS 142 requires that an impairment evaluation be performed annually and at the same time each year. The Company performed its annual evaluation as of January 1, 2003 and no further impairment was indicated. The Company adopted SFAS 143 effective January 1, 2003. SFAS 143 applies to legal obligations associated with the retirement of tangible long-lived assets (ARO) and requires the Company to recognize, as a liability, the fair value of an ARO in the period in which it is incurred and to accrete the liability to its present value in future periods. As of December 31, 2002, prior to the adoption of SFAS 143, the Company carried deferred debits and deferred credits each totaling approximately $87 million related to the decommissioning and dismantling of Summer Station and the funding thereof. Effective January 1, 2003, in connection with the measurement of the ARO upon the adoption of SFAS 143, the amounts reflected within these regulatory assets and liabilities were recharacterized. The following table presents such recharacterized amounts related to the decommissioning obligation and the funding thereof as recorded in the condensed consolidated balance sheet as of September 30, 2003, and the pro forma amounts that would have been recorded as of December 31, 2002 and 2001 had SFAS 143 been adopted at the beginning of 2001. As of September 30, December 31, December 31, Millions of dollars 2003 2002 2001 - ------------------- Actual Proforma Proforma Assets: Within electric plant $40 $40 $40 Within accumulated depreciation (13) (13) (12) Assets held in trust (net) - nuclear decommissioning 35 39 35 Within other regulatory assets 54 45 42 ---------------- --------------- --------------- ---------------- --------------- --------------- Total $116 $111 $105 ================ =============== =============== ================ =============== =============== Liabilities: Asset retirement obligation - nuclear plant decommissioning $116 $111 $105 ================ =============== =============== Proforma net income (loss) and earnings (loss) per share for periods prior to the adoption of SFAS 143 would not differ from amounts actually recorded during these periods. The Company believes that there is legal uncertainty as to the existence of environmental obligations associated with certain transmission and distribution properties. The Company believes that any ARO related to this type of property would be insignificant and, due to the indeterminate life of the related assets, an ARO could not be reasonably estimated. The Company adopted SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," effective January 1, 2003. The provisions of SFAS 145, among other things, discontinue treatment of gains or losses from the early extinguishment of debt as extraordinary items unless such early extinguishment meets the criteria of Accounting Principles Board Opinion (APB) 30. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 145. The Company adopted SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," effective January 1, 2003. This statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 146. The Company adopted the disclosure provisions of SFAS 148, "Accounting for Stock-Based Compensation - Transition and Disclosure," effective January 1, 2003. SFAS 148 requires prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 148. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" was issued in April 2003. SFAS 149 amends and clarifies accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133, "Accounting for Derivative Instruments and Hedging Activities". SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 149. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" was issued in May 2003. SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). SFAS 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 150. C. Equity Compensation Plan

Under the SCANA Corporation Long-Term Equity Compensation Plan (the ~~"Plan")~~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"~~Employees," and related interpretations. In addition, the Company has adopted the disclosure provisions of SFAS 123, "Accounting for Stock-Based Compensation" and ~~effective January 1, 2003, the disclosure provisions of~~ SFAS 148, "Accounting for Stock-Based Compensation-Transition and Disclosure." ~~At September 30, 2003, options issued and outstanding under the Plan totaled approximately 1.5 million.~~

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

compensation expense for the issuance of options based on the fair value method described in SFAS 123, pro forma net income and earnings ~~(loss)~~ per share would have been as presented below:
Three Months Ended Nine Months Ended September 30, September 30, 2003 2002 2003 2002 ---- ---- ---- ---- Net income (loss) - as reported (millions) $84 $78 $242 $(184) Net income (loss) - pro forma (millions) $83 $78 $240 $(184) Basic and diluted earnings (loss) per share - as reported $.76 $.74 $2.18 $(1.76) Basic and diluted earnings (loss) per share - pro forma $.75 $.74 $2.16 $(1.76)

	Three Months Ended March 31,
	2004		2003
Net income—as reported (millions)	$	101.2	$	83.6
Net income—pro forma (millions)	$	100.9	$	83.2
Basic and diluted earnings per share—as reported	$	.91	$	.75
Basic and diluted earnings per share—pro forma	$	.91	$	.75

No options have been granted since 2002.

C. Pension and Other Postretirement Benefit Plans

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

							Other Postretirement Benefits
	Pension Benefits
Three months ended March 31 (Millions of dollars)	Pension Benefits
Three months ended March 31 (Millions of dollars)	2004			2003			2004		2003
Service cost	$	2.8		$	2.6		$	0.8	$	1.3
Interest cost		9.1			9.5			2.9		3.8
Expected return on assets		(17.7	)		(15.0	)		—		—
Prior service cost amortization		1.6			1.6			0.2		0.8
Transition obligation amortization		0.2			0.2			0.3		0.3
Actuarial (gain) loss		—			0.5			0.5		0.2

Net periodic benefit (income) cost	$	(4.0	)	$	(0.6	)	$	4.7	$	6.4

D. Earnings ~~(Loss)~~ Per Share

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

E. Affiliated Transactions

SCE&G holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel. SCE&G had recorded as receivables from these affiliated companies ~~for these investments~~ approximately ~~$15.4~~$17.8 million and ~~$8.5~~$13.4 million at ~~September 30, 2003~~March 31, 2004 and December 31, ~~2002,~~2003, respectively. SCE&G had recorded as payables to these affiliated companies ~~for these investments~~ approximately ~~$14.3~~$15.6 million and ~~$8.0~~$12.2 million at ~~September 30, 2003~~March 31, 2004 and December 31, ~~2002,~~2003, respectively.

F. Reclassifications

Certain amounts from prior periods have been reclassified to conform with the presentation adopted for ~~2003.~~ 2004.

2. ACCOUNTING CHANGE As a result of the January 1, 2002 adoption of SFAS 142, the Company recorded a $230 million impairment charge related to the acquisition adjustment recorded in connection with its investment in PSNC Energy. This charge is reflected on the Condensed Consolidated Statements of Operations as the cumulative effect of an accounting change. See additional information at Note 1B. 3. RATE AND OTHER REGULATORY MATTERS

South Carolina Electric & Gas Company (SCE&G)

Electric In January 2003 the SCPSC issued an order granting SCE&G a composite increase in retail electric rates of approximately 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, based on the level of revenues and operating expenses, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.

In January 2003, in conjunction with the approval of ~~the above~~a retail rate increase, the SCPSC approved SCE&G's request to reduce the fuel component to 1.678 cents per KWh. This reduction was effective for service rendered on and after February 1, 2003. In April 2003 the SCPSC issued an order approving SCE&G's request to maintain the fuel cost component of rates at 1.678 cents per KWh, effective May 1, 2003. The SCPSC also reaffirmed the prudence of SCE&G's purchasing practices and recognized the efficiency of SCE&G's electric generating plants; however, it deferred action on the recovery of certain purchased power costs pending the resolution of the appeal ~~discussed below.~~of the SCPSC's May 2002 order. In May 2002 the SCPSC ~~issued an order approving~~approved SCE&G's request to increase the fuel component of rates charged to electric customers, ~~from 1.579 cents per KWh to 1.722 cents per KWh. The increase~~which reflected higher fuel costs projected for the period May 2002 through April 2003. The increase also provided continued recovery for under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of SCE&G's base load generating plants in winter 2000-2001. The ~~new rates were effective as of the first billing cycle in May 2002. The~~ Consumer Advocate of South Carolina (Consumer Advocate) appealed to the South Carolina Circuit Court (Circuit Court) the portion of the SCPSC's order related to the recovery of certain purchased power costs. The ~~appeal is still pending.~~ Circuit Court ruled that the current fuel clause only provides for the recovery of the fuel costs included in purchased power and not the total cost of the power purchased. The Circuit Court remanded the case to the SCPSC for final disposition. In April 2004 the SCPSC approved a stipulation agreement between the Consumer Advocate and SCE&G whereby SCE&G would be allowed to defer for recovery in a future rate proceeding the portion of the purchased power costs not allowed to be recovered through the fuel clause.

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

Gas

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

SCE&G's cost of gas component in effect during the period January 1, ~~2002~~2003 through ~~September 30, 2003~~March 31, 2004 was as follows: Rate Per Therm Effective Date Rate Per Therm Effective Date $.728 January-February 2003 $.596 January-October 2002 $.928 March-September 2003 $.728 November-December 2002 On October 28, 2003, as part of the annual review of gas costs, the SCPSC approved SCE&G's request to decrease the cost of gas component from $.928 per therm to $.867 per therm effective with the first billing cycle in November 2003.

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

The SCPSC allows SCE&G to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former MGPs. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for SCE&G's gas operations that had previously been recorded in deferred debits. In October 2003, as a result of the annual review, the SCPSC approved SCE&G's request to reduce the billing surcharge from 3.0 cents per therm to ~~2.2~~0.8 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2009, of the balance remaining at ~~September 30, 2003~~March 31, 2004 of ~~$11.6~~$9.8 million.

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

PSNC Energy's rates are established using a benchmark cost of gas approved by the NCUC, which may be modified periodically to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or

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, ~~2002~~2003 through ~~September 30, 2003~~March 31, 2004 was as follows: ~~Rate Per Therm Effective Date Rate Per Therm Effective Date $.460 January-February 2003 $.300 January 2002 $.595~~

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

For service rendered on and after March 2003 $.215 February-June 2002 $.725 April-September 2003 $.350 July-October 2002 $.410 November-December 2002 On October 13, 2003 in connection with PSNC Energy's 2003 Annual Prudence Review1, 2004, the NCUC ~~determined that~~authorized PSNC ~~Energy's gas costs, including all hedging transactions, were reasonable~~Energy to implement decrements in its sales and ~~prudently incurred during the 12-month review period ended March 31, 2003. The NCUC also authorized new~~transportation rate ~~decrements~~schedules to ~~refund overcollections~~reflect a decrease of ~~certain gas costs included~~approximately $5.7 million in PSNC Energy's ~~deferred accounts, effective November 1, 2003.~~annual fixed gas costs as well as the current over-recovery of approximately $16.5 million.

A state expansion fund, established by the North Carolina General Assembly and funded by refunds from PSNC Energy's interstate pipeline transporters, provides financing for expansion into areas that otherwise would not be economically feasible to serve. In June 2000 the NCUC approved PSNC Energy's requests for disbursement of up to $28.4 million from PSNC Energy's expansion fund to extend natural gas service to Madison, Jackson and Swain Counties in western North Carolina. PSNC Energy estimates that the cost of this project will be approximately ~~$31.4~~$31 million. The Madison County and Jackson County portions of the project were completed in 2002, and the Swain County portion ~~is expected to be~~was completed and placed in ~~the spring of~~service in April 2004. Through ~~September 30, 2003~~March 31, 2004 approximately ~~$24.4~~$29 million had been spent on this project.

In December 1999 the NCUC issued an order approving ~~SCANA's~~the Company's acquisition of PSNC Energy. As specified in the order, PSNC Energy agreed to a moratorium on general rate cases until August 2005. General rate relief can be obtained during this period to recover costs associated with material adverse governmental actions and force majeure events. South Carolina Pipeline Corporation (SCPC) SCPC's purchased gas adjustment for cost recovery and gas purchasing policies are reviewed annually by the SCPSC. In an order dated August 5, 2003 the SCPSC found that for the period April 2002 through December 2002 SCPC's gas purchasing policies and practices were prudent and SCPC properly adhered to the gas cost recovery provisions of its gas tariff. 4.

3. LONG-TERM DEBT

On January 13, 2003 the Company retired at maturity $60 million of 6.05% medium-term notes. On January 23, 2003 SCE&G issued $200 million First Mortgage Bonds having an annual interest rate of 5.80% and maturing on January 15, 2033. The proceeds from the sale of these bonds were used to reduce short-term debt and for general corporate purposes. On April 4, 2003 the Company redeemed $100 million of floating rate medium-term notes that were set to mature August 8, 2003. The notes were bearing interest at a rate of 2.215% when redeemed. On May 21, 2003 SCE&G issued $300 million First Mortgage Bonds having an annual interest rate of 5.30% and maturing on May 15, 2033. SCE&G used the net proceeds from the sale of these bonds and certain other SCE&G funds to redeem its $100 million principal amount of 7.625% First Mortgage Bonds due June 1, 2023, its $150 million principal amount of 7.50% First Mortgage Bonds due June 15, 2023 and its Junior Subordinated Debentures which effected the redemption of $50 million aggregate amount of 7.55% Trust Preferred Securities, Series A, issued by SCE&G Trust I. On July 1, 2003 the Company retired at maturity $20 million of 6.51% medium-term notes and, on July 8, 2003 the Company retired at maturity $75 million of 6.5% medium-term notes. On August 26, 2003 Berkeley County, South Carolina, issued its $35,850,000 Pollution Control Facilities Revenue Refunding Bonds, Series 2003. The proceeds of these bonds were loaned by the County toFebruary 11, 2004 South Carolina Generating Company, Inc. (GENCO), issued $100 million of senior secured promissory notes maturing February 1, 2024 and ~~applied to defease GENCO's obligation with the respect to the County's $35,850,000 Pollution Control Facilities Revenue Refunding Bonds, Series 1984 (bearing interest at~~bearing a ~~rate of 6.50%). The 2003 refunding bonds have an annual~~fixed interest rate of ~~4.875%~~5.49%. Proceeds from this issuance were used to support GENCO's construction program and ~~mature on October 1, 2014. 5.~~to repay intercompany advances borrowed for that purpose.

4. RETAINED EARNINGS

The Company's Restated Articles of Incorporation do not limit the dividends that may be paid on its common stock. However, the Restated Articles of Incorporation of SCE&G contain provisions that, under certain circumstances, could limit the payment of cash dividends on its common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At ~~September 30, 2003~~March 31, 2004 approximately ~~$43.4~~$45.3 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G's common stock. 6.

5. FINANCIAL INSTRUMENTS

Investments

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

mark-to-market accounting and some of which are considered cost basis investments for which determination of fair value historically has been considered impracticable. Equity holdings subject to SFAS 115 are categorized as "available for sale" and are carried at quoted market prices, with any unrealized gains and losses credited or charged to other comprehensive income (loss) within common equity on the Company's balance sheet. Debt securities and preferred stock with significant debt characteristics are categorized as "held to maturity" and are carried at amortized cost. When indicated, and in accordance with its stated accounting policy, the Company performs periodic assessments of whether any decline in the value of these securities to amounts below the Company's cost basis is other than temporary. When other than temporary declines occur, write-downs are recorded through operations, and new (lower) cost bases are established.
~~Telecommunications Investments At September 30, 2003~~The Company also holds investments in several partnerships and joint ventures, some of which are accounted for using the equity method.
At March 31, 2004 SCANA Communications Holdings, Inc. (SCH), a wholly owned, indirect subsidiary of the Company, held investments in the equity and debt securities of the following companies in the amounts noted in the table below. Investee Securities Basis - ---------------------- ------------------------------------------------------------- ----------------------- (Millions of dollars) Magnolia Holding 6.2 million shares nonvoting common stock $2.1 ITC^DeltaCom 566.0 thousand shares of common stock 1.1 157.3 thousand shares series A 8% preferred stock, convertible in 2005 into 2.8 million shares of common 13.0 stock Warrants to purchase 506.9 thousand shares of common stock 1.1 Knology 7.2 million shares series A preferred stock, convertible into 7.5 million shares of common stock 14.0 18.1 million shares series C preferred stock, convertible into 18.1 million shares of common stock 33.9 21.7 million shares series E preferred stock, convertible into 21.7 million shares of common stock 40.6 12% senior unsecured notes due 2009, including accrued 48.0 interest
~~In May 2003 the Company's investment in ITC Holding Company, Inc. was sold and in September 2003 the working capital true-up for the sale was completed. The transaction resulted~~ in the ~~receipt of net after-tax cash proceeds of approximately $48 million~~following equity and ~~the receipt of an investment interest in a newly formed entity,~~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
	163.6 thousand shares series A 8% preferred stock, convertible into 2.8 million shares of common stock		13.2
	Warrants to purchase 506.9 thousand shares of common stock		1.1
Knology	2.6 million shares of common stock		23.1
	2.2 million shares of nonvoting common stock		19.6
	13% senior unsecured notes due 2009, including accrued interest		51.1
	Warrants to purchase 16.5 thousand shares of common stock		—

Magnolia Holding Company, LLC (Magnolia Holding)~~. A book gain, net of tax, of approximately $39 million was realized upon this transaction. Magnolia Holding~~, holds ownership interests in several Southeastern communications companies.

ITC^DeltaCom, Inc. (ITC^DeltaCom) is a regional provider of telecommunications services. The common shares of ITC^DeltaCom owned by SCH had a market value of $3.7 million, and the warrants owned have a market value of ~~$3.1 million.~~$2.0 million as of March 31, 2004. The ITC^DeltaCom preferred shares owned by SCH are classified as held to maturity due to their debt features, and ~~the~~their market value is not readily determinable.

Knology, Inc. (Knology) is a ~~broadband service~~fully integrated provider of ~~cable television, telephone~~video, voice, data and ~~internet services. In June 2003, based upon valuation information obtained~~advanced communication services to residential and business customers in ~~connection with~~ the ~~Magnolia Holding transaction,~~southeastern United States. The common shares of Knology (voting and non-voting) owned by SCH ~~recorded impairment losses associated with~~had a market value of $32.6 million as of March 31, 2004.

Derivatives

The Company follows the Knology investment totaling $4.8 million, net of taxes. In August 2003, Magnolia Holding distributed its holdings in Knology preferred stock to Magnolia Holding's members. As a result, SCH's basis in Magnolia Holding was reducedguidance required by ~~and SCH's basis in Knology was increased by, approximately $6.2 million. Derivatives SFAS~~FAS 133 "Accounting for Derivative Instruments and Hedging Activities," as amended, ~~requires the Company to recognize all derivative instruments as either assets or liabilities~~ in ~~the statement of financial position and to measure~~accounting for derivatives, including those instruments at fair value. SFAS 133 further provides that changes in the fair value of derivative instruments are either recognized in earnings or reported as a component of other comprehensive income (loss), depending upon the intended use of the derivative and the resulting designation. The fair value of the derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or quotationsarising from independent parties. Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by the Company. The Company's Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure. The Risk Management Committee, which is comprised of certain officers, including the Company's Risk Management Officer and senior officers of the Company, apprises the Board of Directors with regard to the management of risk and brings to the Board's attention any areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions. ~~Commodities The Company uses derivative instruments to hedge anticipated future purchases of natural gas, which create market risks of different types. Instruments designated as~~ cash flow hedges related to natural gas. The Company also utilizes swap agreements to manage interest rate risk. These transactions are ~~used~~more fully described in Note 9 to ~~hedge risks associated with fixed price obligations~~the consolidated financial statements in a volatile price market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to hedge operational storage assets. The basic types of financial instruments utilized are exchange-traded instruments, such as New York Mercantile Exchange futures contracts or options, and over-the-counter instruments such as swaps, which are typically offered by energy and financial institutions.the Company's 2003 Form 10-K.

The Company recognized gains ~~(losses)~~ of approximately ~~$(0.4)~~$1.9 million ~~net of tax,~~ and ~~$5.4~~$5.6 million, net of tax, as a result of qualifying cash flow hedges ~~related to nonregulated operations~~whose hedged transactions occurred during the three months

ended March 31, 2004 and nine months ended September 30, 2003. The Company recognized gains (losses) of approximately $0.1 million and $(21.9) million, net of tax, as a result of qualifying cash flow hedges related to nonregulated operations during the three and nine months ended September 30, 2002.2003, respectively. These ~~gains and losses~~amounts were recorded in cost of gas. The Company estimates that most of the ~~September 30, 2003~~March 31, 2004 unrealized ~~loss~~gain balance of ~~$1.3~~$3.2 million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in 2004 and 2005 as ~~an increase~~a decrease to ~~realized~~ gas cost if market prices remain stable. As of ~~September 30, 2003~~March 31, 2004, all of the Company's cash flow hedges settle by their terms before the end of 2006. ~~The Company recorded option~~

Option premiums ~~of $0.5 million~~ and gains ~~of $0.3 million, net of tax, as a result of~~resulting from qualifying fair value hedges during the three ~~and nine~~ months ended ~~September 30,~~March 31, 2004 and 2003 ~~respectively. The premiums~~were insignificant and ~~gains~~ were recorded in cost of gas. As of ~~September 30, 2003~~March 31, 2004 all of the Company's fair value hedges had settled. In January 2003 PSNC Energy filed a summary of its hedging program for natural gas purchases with the NCUC for informational purposes. The primary goal of the program is to reduce price volatility to firm customers. In an October 2003 order, the NCUC declared the program was reasonable. Transaction fees and any gains or losses are recorded in deferred accounts for subsequent rate consideration. As of September 30, 2003 PSNC Energy had deferred a net gain of approximately $0.6 million. SCPC's tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCPC's hedging activities are to be included in the PGA. As such, costs of related derivatives that SCPC utilizes to hedge its gas purchasing activities are recoverable through its weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a current asset or liability. Interest Rates The Company uses interest rate swap agreements to manage interest rate risk. These swap agreements provide for the Company to pay variable rate and receive fixed rate interest payments and are designated as fair value hedges of certain debt instruments. The Company may terminate a swap agreement and may replace it with a new swap also designated as a fair value hedge. Payments received upon termination of a swap are recorded as basis adjustments to long-term debt and are amortized as reductions to interest expense over the term of the underlying debt. The fair value of interest rate swaps is recorded within other deferred debits on the balance sheet. The resulting credits serve to reflect the hedged long-term debt at its fair value. Periodic receipts or payments related to the interest rate swaps are credited or charged to interest expense as incurred.

At ~~September 30, 2003~~March 31, 2004 the estimated fair value of the Company's swaps totaled ~~$12.1~~$14.3 million (gain) related to combined notional amounts of ~~$337.4~~$333.1 million. In anticipation of the issuance of debt, the Company also uses interest rate lock or similar agreements to manage interest rate risks. Payments received or made upon termination of such agreements are recorded within other deferred debits on the balance sheet and are amortized to interest expense over the term of the underlying debt. In connection with the issuance of First Mortgage Bonds in May 2003, the Company paid approximately $11.9 million upon the termination of a treasury lock agreement. 7.

6. COMMITMENTS AND CONTINGENCIES

Reference is made to Note ~~12 of Notes~~10 to ~~Consolidated Financial Statements~~the consolidated financial statements appearing in the Company's Annual Report on Form 10-K for the year ended December 31, ~~2002.~~2003. Commitments and contingencies at ~~September 30, 2003~~March 31, 2004 include the following:

A. Lake Murray Dam Reinforcement

In October 1999 the United States Federal Energy Regulatory Commission (FERC) mandated that SCE&G reinforce its Lake Murray ~~dam~~Dam in order to comply with new federal safety ~~standards and maintain the lake in case of an extreme earthquake.~~standards. Construction for the project and related activities, which began in the third quarter of 2001 is expected to cost approximately $275 million and be completed in 2005. Costs incurred through ~~September 30, 2003~~March 31, 2004 totaled approximately ~~$126~~$192 million.

B. Nuclear Insurance

The Price-Anderson Indemnification Act, which deals with public liability for a nuclear incident, currently establishes the liability limit for third-party claims associated with any nuclear incident at ~~$10.9~~$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. ~~The~~

Congress failed to renew the Price-Anderson Indemnification Act ~~was anticipated to renew in August 2002. However, Congress concluded their session in 2002 without approving this renewal. The Act is now expected to renew with only modest changes~~when it expired in 2003. The delayed renewal has no impact on ~~SCE&G at present~~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. If such an incident were to occur, it would have a material adverse impact on the Company's results of operations, cash flows and financial position.

C. Environmental

The Company maintains an environmental assessment program to identify and evaluate current and former ~~operations~~ sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate solely to regulated operations.

South Carolina Electric & Gas Company

At SCE&G, site assessment and cleanup costs are deferred and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled ~~$11.6~~$9.8 million at ~~September 30, 2003.~~March 31, 2004. The deferral includes the estimated costs associated with the following matters.

SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for benzene contamination in the intermediate aquifer on surrounding properties. SCE&G anticipates that the remaining remediation activities will be completed by the end of 2004, with certain monitoring and retreatment activities continuing until 2007. As of ~~September 30, 2003,~~March 31, 2004, SCE&G has spent approximately ~~$19.6~~$19.8 million to remediate the Calhoun Park ~~site. Total remediation costs are estimated~~site and expects to ~~be $21.9~~spend an additional $2 million.

SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by the South Carolina Department of Health and Environmental Control (DHEC). SCE&G is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. In addition, in March 2003 SCE&G signed a consent agreement with DHEC related to a site formerly owned by SCE&G. The site contained residue material that was moved from an MGP site. The removal action for this site has been completed. SCE&G anticipates that major remediation activities for the three owned sites will be completed before 2006. As of ~~September 30, 2003,~~March 31, 2004, SCE&G has spent approximately ~~$3.9~~$3.1 million related to these ~~three~~ sites, and expects to spend an additional ~~$5.2~~$4.9 million. ~~Total remediation costs are estimated to be $9.1 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 ~~$7.5~~$6.8 million, which reflects the estimated remaining liability at ~~September 30, 2003.~~March 31, 2004. Amounts incurred and deferred to date that are not currently being recovered through gas rates are approximately ~~$1.5~~$2.4 million. Management believes that all MGP cleanup costs incurred will be recoverable through gas rates.

D. ~~Long-Term Natural Gas Contract~~Claims and Litigation

In ~~2001~~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 ~~subsidiary~~contract for the sale of assets to the plaintiff and various causes of action associated with that contract. The Company ~~entered into, in~~does not believe that the ~~ordinary course~~resolution of ~~business,~~this issue will have a ~~15-year take-and-pay contract with an unaffiliated natural gas supplier to purchase 190,000 DT~~material impact on its results of ~~natural gas per day beginning in the spring of 2004. In December 2002,~~operations, cash flows or financial position.

On August 21, 2003, SCE&G was served as a ~~result~~co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and South Carolina Electric & Gas Company, in South Carolina's Circuit Court of the failure of the supplier and its guarantor to meet contractual obligations related to credit support provisions, the subsidiary terminated the contract and the supplier initiated arbitration. A hearing under the binding arbitration provisions of the contract was postponed from September 2003 until at least January 2004 after the parties made progress towards a settlement. In initial pleadingsCommon Pleas for the ~~hearing,~~Fifth Judicial Circuit. The plaintiffs are seeking damages for the ~~supplier demanded payment~~alleged improper use of ~~at least $134 million in damages from~~electric transmission easements but have not asserted a dollar amount for their claims. Specifically, the ~~subsidiary; conversely,~~plaintiffs contend that the ~~subsidiary demanded payment~~licensing of ~~no less~~attachments on electric utility poles, towers and other facilities to non-utility third parties or telecommunication companies for other than ~~$154 million in damages from~~ the ~~supplier.~~electric utilities' internal use along the electric transmission line right-of-way constitutes a trespass. The Company is confident of the propriety of its actions and ~~will vigorously pursue its position if the arbitration hearing is held.~~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. ~~E. Parts Availability Agreement In June 2002~~

A complaint was filed on October 22, 2003 against SCE&G ~~entered into~~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 ~~parts availability agreement~~municipality's limits. The complaint also alleges that SCE&G failed to obey, observe, or comply with ~~a supplier whereby turbine and stator bar parts will be stored by SCE&G to be available when needed. The parts will remain~~ the ~~property~~lawful order of the ~~supplier until such time as they~~SCPSC by charging franchise fees to those not residing within a municipality. The complaint seeks restitution to all affected customers and penalties up to $5,000 for each separate violation. SCE&G is confident of the reasonableness of its actions and intends to mount a vigorous defense. The allegations contained in the complaint are ~~removed from storage by~~the subject of a similar lawsuit that was filed and served on SCE&G, for which a Motion to Dismiss is pending. The allegations are also the subject of a purported class action lawsuit filed on or about December 12, 2003 against Duke Energy Corporation, Progress Energy Services Company and ~~payment is made.~~SCE&G. SCE&G ~~bears~~believes that the ~~risk~~resolution of ~~loss~~these actions will not have a material adverse impact on its results of operations, cash flows or ~~repair for any part damaged while in storage and will pay an availability fee each quarter based on the daily available parts stored.~~financial condition. In addition, SCE&G ~~is obligated~~filed a petition with the SCPSC on October 23, 2003 pursuant to ~~purchase all remaining stored parts at~~S. C. Code Ann. R.103-836. The petition requests that the ~~termination dates~~SCPSC exercise its jurisdiction to investigate the operation of the ~~contract, June 2009 for~~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 ~~turbine parts~~system which will reduce such errors in the future, and ~~December 2006 for~~to adopt any regulation which the ~~stator bar parts. As such, SCE&G has recorded a liability~~SCPSC deems just and proper to regulate the franchise fee collection process.

The Company is also engaged in ~~Other Long-Term Debt with an offsetting asset in Deferred Debits. At September 30, 2003 SCE&G had recorded $30.8 million for~~various other claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the ~~turbine parts and $3.2 million for the stator bar parts.~~ 8.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. ~~Accumulated depreciation is not assignable to Electric Operations and Gas Distribution segments; therefore, it is reflected as an adjustment to arrive at the consolidated total assets.~~ Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy which meet SFAS 131 criteria for aggregation.

Disclosure of Reportable Segments (Millions of dollars) - ---------------------------------- ------------- -------------- --------------- ----------------- Three Months Ended External Intersegment Operating Net September 30, 2003 Revenue Revenue Income (Loss) Income (Loss) - ---------------------------------- ------------- -------------- --------------- ----------------- Electric Operations $429 $1 $162 n/a Gas Distribution 114 - (16) n/a Gas Transmission 41 53 2 n/a Retail Gas Marketing 60 - n/a $- Energy Marketing 107 - n/a 1 Telecommunications Investments - - n/a 3 All Other - 65 - (2) Adjustments/Eliminations - (119) 2 82 - ---------------------------------- ------------- -------------- --------------- ----------------- - ---------------------------------- ------------- -------------- --------------- ----------------- Consolidated Total $751 $- $150 $84 ================================== ============= ============== =============== ================= - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Nine Months Ended External Intersegment Operating Net Segment September 30, 2003 Revenue Revenue Income Income (Loss) Assets - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Electric Operations $1,121 $4 $343 n/a $6,337 Gas Distribution 603 - 40 n/a 1,465 Gas Transmission 172 225 11 n/a 328 Retail Gas Marketing 320 - n/a $17 84 Energy Marketing 330 - n/a (1) 50 Telecommunications Investments - - n/a 36 218 All Other - 204 - (5) 238 Adjustments/Eliminations - (433) 24 195 (932) - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Consolidated Total $2,546 $- $418 $242 $7,788 ================================== ============= ============== =============== ================= =============== - ---------------------------------- ------------- -------------- --------------- ----------------- Three Months Ended External Intersegment Operating Net September 30, 2002 Revenue Revenue Income (Loss) Income (Loss) - ---------------------------------- ------------- -------------- --------------- ----------------- Electric Operations $424 $1 $166 n/a Gas Distribution 85 1 (12) n/a Gas Transmission 51 54 6 n/a Retail Gas Marketing 46 - n/a $(3) Energy Marketing 88 - n/a - Telecommunications Investments - - n/a (1) All Other - 74 - (1) Adjustments/Eliminations - (130) (6) 83 - ---------------------------------- ------------- -------------- --------------- ----------------- Consolidated Total $694 $- $154 $78 ================================== ============= ============== =============== ================= - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Nine Months Ended External Intersegment Operating Net Segment September 30, 2002 Revenue Revenue Income (Loss) Income (Loss) Assets - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Electric Operations $1,075 $4 $339 n/a $5,722 Gas Distribution 428 1 40 n/a 1,615 Gas Transmission 159 185 3 n/a 305 Retail Gas Marketing 265 - n/a $10 74 Energy Marketing 238 - n/a (2) 43 Telecommunications Investments - - - (154) 341 All Other - 207 - 2 349 Adjustments/Eliminations - (397) 14 (40) (870) - ---------------------------------- ------------- -------------- --------------- ----------------- --------------- Consolidated Total $2,165 $- $396 $(184) $7,579 ================================== ============= ============== =============== ================= ===============
~~9. SUBSEQUENT EVENT On November 6, 2003 SCE&G issued $250 million First Mortgage Bonds having an annual interest rate~~ of ~~5.25% and maturing on November 1, 2018. SCE&G will use the net proceeds from the sale~~Reportable Segments
(Millions of these bonds for the payment at maturity of SCE&G's $100 million principal amount of 6.25% First Mortgage Bonds due December 15, 2003, for repayment of short-term debt primarily incurred as a result of SCE&G's construction program and for general corporate purposes. dollars)

Three Months Ended March 31, 2004	External Revenue			Intersegment Revenue			Operating Income		Net Income			Segment Assets
Electric Operations	$	380		$	1		$	96		n/a		$	5,134
Gas Distribution		370			2			58		n/a			1,449
Gas Transmission		54			118			6		n/a			313
Retail Gas Marketing		218			—			n/a	$	20			145
Energy Marketing		112			3			n/a		—			51
All Other		15			68			1		1			684
Adjustments/Eliminations		(13	)		(192	)		33		80			773

Consolidated Total	$	1,136		$	—		$	194	$	101		$	8,549

March 31, 2003
Electric Operations	$	336		$	2		$	84		n/a		$	4,566
Gas Distribution		343			—			61		n/a			1,416
Gas Transmission		84			108			5		n/a			317
Retail Gas Marketing		183			—			n/a	$	13			124
Energy Marketing		123			—			n/a		(2	)		67
All Other		14			67			—		(1	)		601
Adjustments/Eliminations		(14	)		(177	)		18		74			1,086

Consolidated Total	$	1,069		$	—		$	168	$	84		$	8,177

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

SCANA CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in SCANA Corporation's ~~(the~~(together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, ~~2002.~~2003.

Statements included in this discussion and analysis (or elsewhere in this quarterly report) which are not statements of historical fact are intended to be, and are hereby identified as, "forward-looking statements" for purposes of the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following: (1) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) changes in the utility and nonutility regulatory environment, (3) changes in the economy, especially in areas served by the Company's subsidiaries, (4) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (5) growth opportunities for the Company's regulated and diversified subsidiaries, (6) the results of financing efforts, (7) changes in the Company's accounting policies, (8) weather conditions, especially in areas served by the Company's subsidiaries, (9) performance of and marketability of the Company's investments in telecommunications companies, (10) performance of the Company's pension plan assets, (11) inflation, (12) changes in environmental regulations, (13) volatility in commodity natural gas markets and (14) the other risks and uncertainties described from time to time in the Company's periodic reports filed with the United States Securities and Exchange Commission. The Company disclaims any obligation to update any forward-looking statements. ~~COMPETITION~~

Electric Operations

In ~~South Carolina electric restructuring efforts remain stalled,~~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 ~~state legislature adjourned for~~Task Force believes would improve reliability of North America's interconnected bulk power system (the grid). Full implementation of the ~~year without considering electric restructuring legislation. At~~Blackout Report's recommendations would require a number of actions by legislative, regulatory and industry participants. However, the ~~federal level, energy legislation~~Blackout Report asserts as its single most important recommendation that the U.S. Congress should enact the reliability provisions contained in the Energy Bill, different versions of which passed ~~both houses of Congress in 2003, though significant differences exist between~~ the House and Senate ~~versions. Some~~in 2003 but have stalled in conference committee. Various provisions of the ~~more stringent provisions of this~~Energy Bill related to electric reliability are being resubmitted as separate legislation ~~either currently included or expected to be debated in conference committee,~~(reliability legislation). It is anticipated that any reliability legislation, if passed, would ~~require that one percent~~make reliability standards mandatory and enforceable with penalties for non-compliance and would strengthen the role of the electric energy sold by retail electric suppliers, beginning in 2005, escalating to ten percent by 2020, be generated from renewable energy resources. Renewable energy resources, as defined in the legislation, may exclude hydroelectric generation. Substantial penalties would be levied for failure to comply. Electric cooperatives and municipal utilities would be exempt from these requirements. In addition, largely in response to the August 2003 blackout in eight northern states and parts of Canada, the energy legislation being considered includes several provisions to develop and enforce reliability standards for high-voltage transmission systems and to expedite construction of transmission lines. The Company cannot predict whether such legislation will be enacted, and if it is, the conditions it would impose on utilities. In July 2002 the United StatesU.S. Federal Energy Regulatory Commission (FERC) ~~issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design (SMD) which proposed sweeping changes~~, enabling it to enact regulatory initiatives that would significantly change the country's existing regulatory framework governing transmission, open access and energy markets and would attempt, in large measure, to standardize the national energy market. The Company cannot predict whether Congress will enact reliability legislation or the extent to which the other recommendations contained in the Blackout Report will be implemented. If implemented, such legislation could have a significant

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

In addition, the ~~proposed rule~~North American Electric Reliability Council (NERC) is expected to proceed with its initiatives to develop, establish and enforce standards for the grid. To that end, NERC is working closely with FERC to implement stronger reliability standards among NERC's voluntary membership. SCE&G, along with other NERC members, is also working closely with NERC in these efforts. Such initiatives would be significantly influenced by any reliability legislation enacted by Congress. If implemented, such initiatives by FERC and NERC could have a significant impact on ~~South Carolina Electric and Gas Company's (SCE&G)~~SCE&G's access to or cost of power for its native load customers and on SCE&G's marketing of power outside its service territory. On April 28, 2003 FERC issued a "white paper" regarding SMD which describes how the final SMD rule being considered would differ from the NOPR. The Company is currently evaluating FERC's action to determine potential effects on SCE&G's operations. Additional directives from FERC are expected, and would likely be significantly influenced by the energy legislation discussed in the preceding paragraph.

Retail Gas Distribution Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch fromMarketing

In March 2004 SCANA Energy acquired approximately 47,000 retail natural gas ~~to an alternate fuel, such as propane or fuel oil. Natural~~customers formerly served by another gas ~~competes with these alternate fuels based on price. As~~marketer in Georgia. With this transaction, SCANA Energy's total customer base represents about a ~~result, any significant disparity between supply and demand, either~~30 percent share of the 1.5 million customers in Georgia's natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and impact the Company's ability to retain large commercial and industrial customers. Gas Transmission In September 2002 SCG Pipeline, Inc. (SCG) received approval from FERC to acquire an interest in an existing pipeline and to build a pipeline from Elba Island, Georgia to Jasper County, South Carolina. When operational, SCG will provide interstate transportation services for natural gas to markets in southeastern Georgia and South Carolina. SCG will transport natural gas from interconnections with Southern Natural at Port Wentworth, Georgia, and from an import terminal owned by Southern LNG at Elba Island, near Savannah, Georgia. The endpoint of SCG's pipeline is at the site of the natural gas-fired generating station that SCE&G is building in Jasper County, South Carolina. Construction of the pipeline, which began in March 2003, was completed in the third quarter of 2003 at a cost of approximately $32 million. In August 2003 SCPC began construction on phase one of the South System Loop pipeline project. This phase of the pipeline will stretch 38.3 miles from SCE&G's Jasper County generation facility to Yemassee in Hampton County, South Carolina, and will provide a new supply source to SCPC's current system. Completion of phase one of the pipeline is expected in the first quarter of 2004, at a cost of approximately $25 million. South Carolina Pipeline Corporation (SCPC) supplies natural gas to SCE&G for its resale to gas distribution customers and for certain electric generation needs. SCPC also sells natural gas to large commercial and industrial customers in South Carolina and faces the same competitive pressures as gas distribution for these classes of customers. Retail Gas Marketingmarket. SCANA Energy ~~continues to maintain its position as~~remains the second largest natural gas marketer in ~~Georgia with a market share of approximately 25 percent and total customers in excess of 380,000 (including those served under~~ the ~~program described below).~~state.

In March 2004 SCANA Energy's competitors include affiliates of other large energy companies with substantial experience in Georgia's energy market as well as several electric membership cooperatives (EMCs). SCANA's ability to maintain its market share depends onterm for serving low-income and high credit risk customers was extended by the ~~prices it charges customers relative to~~GPSC for an additional year (beginning September 1).

In November 2003 the ~~prices charged by its competitors, its ability to continue to provide high levels of customer service and other factors. The~~ Georgia Public Service Commission (GPSC) ~~continues to implement provisions of the Natural Gas Consumer's Relief Act of 2002 (the Act). Among other things, the Act created~~filed a regulated provider selected through a bidding process to serve low-income and high credit risk customers. The Act also established new service quality standards and addressed assignment of interstate assets. In 2002 SCANA Energy was selected by the GPSC to serve as Georgia's regulated provider for a 2-year period. In this capacity, SCANA Energy serves low-income customers at a rate subsidized by Georgia's Universal Service Fund, and extends service to high credit risk customers who have been denied service by other marketers. At September 30, 2003 approximately 31,000 of SCANA Energy's total customers were being served under this program. In July 2003 the GPSC approved a joint stipulation between the GPSC staff, Atlanta Gas Light Company (AGL) and natural gas marketers (excluding SCANA Energy) dealing with interstate asset capacity and other operational issues. The joint stipulation reduces the frequency whereby AGL can recall capacity previously released to the various gas marketers and streamlines certain gas balancing processes. Though SCANA Energy believes the joint stipulation will improve operations for the gas marketers, SCANA Energy continues to advocate an alternate plan it proposed that would assign interstate asset capacity to those gas marketers choosing assignment and approved by the GPSC. The GPSC has indicated that it intends to file a requestpetition with FERC ~~to obtain~~seeking a declaratory order on the assignment of interstate capacity. That petition addressed the question of whether FERC ~~regulation~~ would preempt ~~or have jurisdiction over SCANA Energy's proposal. The GPSC has not yet filed the request with FERC. If FERC issues a declaratory order,~~ the GPSC ~~is expected~~if a plan proposed by SCANA Energy for the assignment of Atlanta Gas Light Company's interstate capacity assets to ~~evaluate~~certificated natural gas marketers was adopted by the ~~order~~GPSC. On April 15, 2004 FERC ruled that it continues to maintain jurisdiction and ~~determine what action, if any,~~would preempt the GPSC ~~should take on SCANA Energy's proposal.~~ in any plan dealing with interstate capacity assets. SCANA Energy has operated successfully under the current interstate capacity plan and ~~SCANA's other natural~~does not expect that FERC's ruling will have any negative impact on operations.

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

Earnings Per Share

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

	First Quarter
	2004		2003
Reported (GAAP) earnings per share	$	.91	$	.75

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

Pension Income

Pension income was recorded on the Company's financial ~~instruments, including futures contracts and options,~~statements as follows:

		First Quarter
Millions of dollars		First Quarter
Millions of dollars		2004		2003
Income Statement Impact:
	Reduction in (component of) employee benefit costs	$	1.1	$	(1.0	)
	Other income		2.5		1.9
Balance Sheet Impact:
Reduction in (component of) capital expenditures			0.3		(0.3	)
	Component of amount due to Summer Station co-owner		0.1		—

Total Pension Income		$	4.0	$	0.6

For the last several years, the market value of the Company's retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. Pension income in the first quarter of 2004 increased compared to ~~manage their exposure to fluctuating commodity natural gas prices. As~~the corresponding period in 2003 primarily as a ~~part~~result of ~~this risk management process, at any given time,~~a more favorable investment market.

Allowance for Funds Used During Construction (AFC)

AFC is a utility accounting practice whereby a portion of ~~SCANA's projected~~the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. The increase in AFC for the three months ended March 31, 2004 is primarily due to construction expenditures related to the Jasper County Generating Station Project and the Lake Murray Dam Project (see discussion at CAPITAL PROJECTS).

Dividends Declared

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

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

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:

	First Quarter
Millions of dollars	2004		% Change		2003
Operating revenues	$	379.9	13.1	%	$	336.0
Less: Fuel used in generation		95.4	18.1	%		80.8
Purchased power		12.7	21.0	%		10.5

Margin	$	271.8	11.1	%	$	244.7

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

Gas Distribution

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

	First Quarter
Millions of dollars	2004		% Change		2003
Operating revenues	$	371.7	8.3	%	$	343.3
Less: Gas purchased for resale		264.2	14.1	%		231.5

Margin	$	107.5	(3.9	)%	$	111.8

Margin decreased primarily due to decreased recovery of environmental remediation expenses of $3.2 million (offset in operations and maintenance) and an unfavorable competitive position of natural gas ~~needs has been purchased or otherwise placed under contract. Since~~relative to alternate fuels of $1.6 million, partially offset by customer growth and increased consumption of $0.5 million.

Gas Transmission

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

	First Quarter
Millions of dollars	2004		% Change		2003
Operating revenues	$	172.3	(10.5	)%	$	192.4
Less: Gas purchased for resale		157.7	(12.1	)%		179.4

Margin	$	14.6	12.3	%	$	13.0

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

Retail Gas Marketing

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

	First Quarter
Millions of dollars	2004		% Change		2003
Operating revenues	$	217.7	18.5	%	$	183.7
Net income	$	20.6	55.8	%	$	13.2

Operating revenues increased primarily as a ~~competitive market, it may be unable~~result of increased volumes and higher average retail prices. Net income increased primarily due to ~~sustain its current levels~~higher margins of ~~customers and/or pricing, thereby reducing expected~~$8.9 million partially offset by increased bad debt expense of $1.2 million.

Energy Marketing

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

	First Quarter
Millions of dollars	2004			% Change		2003
Operating revenues	$	115.2		(6.0	)%	$	122.4
Net loss	$	(0.5	)	74.6	%	$	(1.8	)

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

Other Operating Expenses

Other operating expenses were as follows:

	First Quarter
Millions of dollars	2004		% Change		2003
Other operation and maintenance	$	154.6	7.3	%	$	144.1
Depreciation and amortization		62.7	4.7	%		59.9
Other taxes		38.8	12.5	%		34.5

Total	$	256.1	7.4	%	$	238.5

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

Other Income (Expense)

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

Income Taxes

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

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its contractual cash obligations will be met through internally generated funds, ~~and~~ the incurrence of additional short-term and long-term ~~indebtedness. Sales~~indebtedness and sales of additional equity ~~securities may also occur.~~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, 2003~~March 31, 2004 was ~~1.87.~~2.95.

Cash requirements for ~~SCANA's~~the Company's regulated subsidiaries arise primarily from their operational needs, funding their construction programs and payment of dividends to ~~SCANA.~~SCANA Corporation. The ability of the regulated subsidiaries to replace existing plant investment, as well as to expand to meet future demand for electricity or gas, will depend on their ability to attract the necessary financial capital on reasonable terms. Regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and these subsidiaries continue their ongoing construction programs, rate increases will be sought. The future financial position and results of operations of the regulated subsidiaries will be affected by their ability to obtain adequate and timely rate and other regulatory relief, if requested. In January 2003 the Public Service Commission of South Carolina (SCPSC) issued an order granting SCE&G a composite increase in retail electric rates of approximately 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, based on the level of revenues and operating expenses, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually without the approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.

The following table summarizes how the Company generated and used funds for property additions and construction expenditures during the ~~nine~~three months ended ~~September 30, 2003~~March 31, 2004 and 2002: - ---------------------------------------------------------------------------- Nine Months Ended September 30, Millions2003:

	Three Months Ended March 31,
Millions of dollars	Three Months Ended March 31,
Millions of dollars	2004			2003
Net cash provided from operating activities	$	163		$	155
Net cash provided from financing activities		67			4
Cash and temporary investments available at the beginning of the period		117			341
Funds used for utility property additions and construction expenditures, net of noncash allowance for funds used during construction	$	122		$	171
Funds used for nonutility property additions		4			3
Funds used for investments		(3	)		(4	)

construction costs of SCE&G's reinforcement dam at Lake Murray. The SCPSC would be expected to render its decision on the ~~beginning~~filing within six months of the period 374 192 Funds used for utility property additions and construction expenditures, net of noncash allowance for funds used during construction $(558) $(424) Funds used for nonutility property additions (6) (12) rate application being filed.

CAPITAL TRANSACTIONS

On ~~January 13, 2003 SCANA retired at maturity $60~~February 11, 2004 GENCO issued $100 million of ~~6.05% medium-term notes. On January 23, 2003 SCE&G issued $200 million of First Mortgage Bonds having an annual~~senior secured promissory notes maturing February 1, 2024 and bearing a fixed interest rate of ~~5.80% and maturing on January 15, 2033. The proceeds~~5.49%. Proceeds from ~~the sale of these bonds~~this issuance were used to reduce short-term debt and for general corporate purposes. On April 4, 2003 SCANA redeemed $100 million of floating rate medium-term notes that were set to mature August 8, 2003. The notes were bearing interest at a rate of 2.215% when redeemed. On May 21, 2003 SCE&G issued $300 million First Mortgage Bonds having an annual interest rate of 5.30% and maturing on May 15, 2033. SCE&G used the net proceeds from the sale of these bonds and certain other SCE&G funds to redeem its $100 million principal amount of 7.625% First Mortgage Bonds due June 1, 2023, its $150 million principal amount of 7.50% First Mortgage Bonds due June 15, 2023 and its Junior Subordinated Debentures which effected the redemption of $50 million aggregate amount of 7.55% Trust Preferred Securities, Series A, issued by SCE&G Trust I. On July 1, 2003 SCANA retired at maturity $20 million of 6.51% medium-term notes, and on July 8, 2003 SCANA retired at maturity $75 million of 6.25% medium-term notes. On August 26, 2003 Berkeley County, South Carolina, issued its $35,850,000 Pollution Control Facilities Revenue Refunding Bonds, Series 2003. The proceeds of these bonds were loaned by the County to South Carolina Generating Company, Inc. (GENCO), and applied to defeasesupport GENCO's obligation with the respect to the County's $35,850,000 Pollution Control Facilities Revenue Refunding Bonds, Series 1984 (bearing interest at a rate of 6.50%). The 2003 refunding bonds have an annual interest rate of 4.875% and mature on October 1, 2014. On November 6, 2003 SCE&G issued $250 million First Mortgage Bonds having an annual interest rate of 5.25% and maturing on November 1, 2018. SCE&G will use the net proceeds from the sale of these bonds for the payment at maturity of SCE&G's $100 million principal amount of 6.25% First Mortgage Bonds due December 15, 2003, for repayment of short-term debt primarily incurred as a result of SCE&G's construction program and to repay intercompany advances borrowed for ~~general corporate purposes.~~ that purpose.

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

CAPITAL PROJECTS ~~In May 2002~~

Construction of SCE~~&G began construction of an~~&G's 875 megawatt generation facility in Jasper County, South Carolina ~~to supply electricity to its South Carolina customers.~~has been completed. The facility ~~will include~~includes three natural gas combustion-turbine generators and one steam-turbine generator. The $450 million facility ~~is expected to begin~~began commercial operation in ~~mid-2004. SCG will transport natural gas~~May 2004. Approximately $276 million of the capital expenditures have been included in rate base, and the remainder are expected to be included in the ~~facility. Costs incurred through September 30, 2003 totaled approximately $421 million.~~rate case previously discussed.

In October 1999 FERC mandated that SCE&G reinforce its Lake Murray ~~dam~~Dam in order to comply with new federal safety ~~standards and maintain the lake in case of an extreme earthquake.~~standards. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost approximately $275 million and be completed in 2005. Costs incurred through ~~September 30, 2003~~March 31, 2004 totaled approximately ~~$126~~$192 million. In 2002 SCE&G entered into 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 above 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, 2003 SCE&G had not yet borrowed under the agreement. In September 2002 SCG Pipeline, Inc. (SCG) received approval from FERC to acquire an interest in an existing pipeline and to build a pipeline from Elba Island, Georgia to Jasper County, South Carolina. When operational, SCG will provide interstate transportation services for natural gas to markets in southeastern Georgia and South Carolina. SCG will transport natural gas from interconnections with Southern Natural at Port Wentworth, Georgia, and from an import terminal owned by Southern LNG at Elba Island, near Savannah, Georgia. The endpoint of SCG's pipeline is at the site of the natural gas-fired generating station that SCE&G is building in Jasper County, South Carolina.

Construction of ~~the pipeline, which began in March 2003,~~SCPC's South System Loop was completed in ~~the third quarter of 2003~~March 2004 at a cost of approximately ~~$32~~$21 million. ~~In August 2003 SCPC began construction on phase one of the South System Loop~~This pipeline ~~project. This phase of the pipeline will stretch~~stretches 38.3 miles from SCG Pipeline's connection with SCE&G's Jasper County generation facility to Yemassee in Hampton County, South Carolina, ~~and will provide~~providing a new supply source to SCPC's current system. ~~Completion of phase one of the pipeline is expected in the first quarter of 2004, at a cost of approximately $25 million.~~

ENVIRONMENTAL MATTERS

For information on environmental matters see Note ~~7C of Notes~~6C to ~~Condensed Consolidated Financial Statements.~~ condensed consolidated financial statements.

OTHER MATTERS

Nuclear Station ~~License Extension~~

In ~~August 2002 SCE&G filed an application with~~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). ~~If approved, the~~The extension ~~would allow~~allows the plant to operate through 2042. At September 30, 2003 SCE&G has capitalized in construction work in progress approximately $7 million related to the application process and expects to capitalize an additional $2 million. SCE&G expects the extension to be issued in mid-2004. Telecommunications Investments In May 2003 the Company's investment in ITC Holding Company, Inc. was sold and in September 2003 the working capital true-up for the sale was completed. The transaction resulted in the receipt of net after-tax cash proceeds of approximately $48 million and the receipt of an investment interest in a newly formed entity, Magnolia Holding Company LLC (Magnolia Holding). A book gain, net of tax, of approximately $39 million was realized upon this transaction. In August 2003, Magnolia Holding distributed its holdings in Knology preferred stock to Magnolia Holding's members. As a result, SCH's basis in Magnolia Holding was reduced by, and SCH's basis in Knology was increased by, approximately $6.2 million.

Synthetic Fuel

SCE&G holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel, the use of which fuel qualifies for federal income tax credits. The aggregate investment in these partnerships as of ~~September 30, 2003~~March 31, 2004 is approximately $3 million, and through ~~September 30, 2003,~~March 31, 2004, they have generated and passed through to SCE&G approximately ~~$83~~$107 million in such tax credits. At ~~September 30, 2003~~March 31, 2004 SCE&G has recorded ~~$59~~on its balance sheet $74 million ofnet deferred

fuel tax benefits, which include partnership losses, net of tax. In addition, ~~PrimeSouth,~~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~~Primesouth does not benefit from any synfuel tax credits.

Under a plan approved by the SCPSC, any tax credits generated and ultimately passed through to SCE&G from synfuel produced for and consumed by SCE&G, net of partnership losses and other expenses, have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions. See Note 1A ~~of Notes~~ to ~~Consolidated Financial Statements. On June 27, 2003~~the condensed consolidated financial statements.

In March 2004 the Company received a "No Change" letter from the Internal Revenue Service (IRS) announced that it is reviewing the scientific validity of certain test procedures and results that have been presented as evidence that solid coal-based synthetic fuels have undergone a significant chemical change. Pending completion of this review, the IRS suspended the issuance of Private Letter Rulings on the question of significant chemical change for requests that rely on the testing procedures and results being reviewed. Upon finishing this review, on October 29, 2003, the IRS issued Announcement 2003-70, finishing its review, and confirming that the test procedures and results used by taxpayers are scientifically valid if the procedures are applied in a consistent and unbiased manner.related to SCE~~&G believes its test procedures will meet the standards contemplated~~&G's interest in the ~~Announcement. Although one of~~synthetic fuel partnership S. C. Coaltech No. l L.P. for the ~~partnerships in which SCE&G owns an interest is currently under audit by~~tax year 2000. This letter supports the ~~IRS, there have been no issues raised with respect to~~Company's position that the ~~validity of~~ synthetic fuel tax ~~credits. While SCE&G is not able to determine what conclusion the IRS will reach in these matters, to the extent the IRS disallows synfuel tax~~ credits generated by either of the two partnerships or the facility managed by PrimeSouth, the Company's and SCE&G's financial position, results of operations and cash flows would not be materially adversely affected. RESULTS OF OPERATIONS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2003 AS COMPARED TO THE CORRESPONDING PERIODS IN 2002 The following discussion of the results of operations of SCANA Corporation and its subsidiaries (the Company) includes a non-GAAP measure, GAAP-adjusted net earnings from operations per share, which excludes from net income (loss) (i) the cumulative effects of mandated changes in accounting principles and (ii) the effects of sales of certain assets and investments and impairment charges related to certain investments. Management believes that GAAP-adjusted net earnings from operations provides a meaningful representation of the Company's fundamental earnings power and improves comparability of period-over-period financial performance. Earnings Per Share GAAP-adjusted net earnings from operations per share of common stock for the third quarter and year to date periods ended September 30, 2003 and 2002 were as follows:
- -------------------------------------------------------------------- -------------------------- ------------------------- Third Quarter Year to Date 2003 2002 2003 2002 - -------------------------------------------------------------------- ------------- ------------ ------------ ------------ Earnings (loss) per share $.76 $.74 $2.18 $(1.76) Less: Realized gain from sale of telecommunications investments .02 - .35 .10 Investment impairments - - (.04) (1.59) Sale of assets - - - .09 Cumulative effect of accounting change, net of taxes - - - (2.20) - -------------------------------------------------------------------- ------------- ------------ ------------ ------------ GAAP-adjusted net earnings from operations per share $.74 $.74 $1.87 $1.84 ==================================================================== ============= ============ ============ ============
Third Quarter 2003 vs 2002 GAAP-adjusted net earnings from operations per share remained unchanged due to improved electric margins of $.05, improved gas margins of $.03, lower interest expense of $.01, reduced income tax expense due primarily to favorable income tax adjustments related to prior periods of $.04 and reduction of preferred dividend requirements of $.01. These factors were offset by higher operation and maintenance expenses of $.06, higher property taxes of $.02, higher depreciation and amortization expense of $.03 and the dilutive effect of the change in shares outstanding of $.03. Earnings per share for 2003 includes a gain of $.02 per share in connection with the working capital true-up for the previously announced sale of ITC Holding shares and the receipt of an investment interest in a newly formed entity (Magnolia Holding) in May 2003. Year to Date 2003 vs 2002 GAAP-adjusted net earnings from operations per share increased $.03 primarily due to higher electric margins of $.29, higher gas margins of $.21, lower interest expense of $.01, reduced income tax expense due primarily to favorable income tax adjustments related to prior periods of $.04 and reduction of preferred dividend requirements of $.01. These factors were partially offset by higher operations and maintenance expenses of $.22, higher depreciation and amortization expenses of $.10, higher property taxes of $.06, the dilutive effect of additional shares outstanding of $.13 and lower equity AFC of $.02. Earnings (loss) per share for 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. The Company also recorded an impairment charge of $.04 per share related to its Knology preferred stock investment in the second quarter. Earnings (loss) per share for 2002 includes a gain of $.10 per share in connection with the sale of Deutsche Telekom AG (DTAG) shares in March 2002. In March 2002 the Company also recorded an impairment write-down of $1.52 per share related to the other than temporary decline in market value of the Company's investment in DTAG and an additional $0.07 per share impairment in June 2002. The Company recorded a $.09 per share gain from the sale of a subsidiary's radio service network in April 2002. Also, as required by SFAS 142 the Company recorded an impairment charge of $2.20 per share, effective January 1, 2002, related to the acquisition adjustment associated with Public Service Company of North Carolina, Incorporated (PSNC Energy). The charge was recorded as the cumulative effect of an accounting change. ~~Pension Income Pension income during the three and nine months ended September 30, 2003 was recorded on the Company's financial statements as follows:~~
- ---------------------------------------------------------------------------------------- ------------------ Third Quarter Year to Date Millions of dollars 2003 2002 2003 2002 - ------------------------------------------------------------------------------ --------- -------- --------- - ------------------------------------------------------------------------------ --------- -------- --------- Income Statement Impact: (Component of) reduction in employee benefit costs $0.5 $1.2 $(1.7) $8.1 Other income 2.2 4.4 6.0 8.3 Balance Sheet Impact: (Component of) reduction in capital expenditures 0.2 0.4 (0.4) 2.3 Component of (reduction in) amount due to Summer Station co-owner 0.1 0.1 (0.1) 0.7 - ------------------------------------------------------------------------------ --------- -------- --------- - ----------------------------------------------------------------------------- -------- --------- Total Pension Income $3.0 $6.1 $3.8 $19.4 ============================================================================= ========= ======== =========
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. However, pension income in all periods of 2003 decreased significantly compared to corresponding periods in 2002 primarily as a result of a less 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 nine months ended September 30, 2003 is primarily the result of the completion of the Urquhart Station repowering project in June 2002. In addition, in January 2003 the SCPSC issued an order allowing SCE&G to include all Jasper County Generating project expenditures as of December 31, 2002 and other construction work in progress expenditures as of June 30, 2002 in electric rate base. At the time the expenditures were included in rate base, AFC was no longer calculated on those amounts. These decreases were partially offset by increased AFC from subsequent construction expenditures related to the Jasper County Generating Station project and the Lake Murray Dam project (see discussion at CAPITAL PROJECTS). Dividends Declared The Company's Board of Directors has declared the following dividends on common stock during 2003 : - ----------------- ------------------- ------------------- --------------------- Declaration Date Dividend Per Share Record Date Payment Date - ----------------- ------------------- ------------------- --------------------- February 20, 2003 $.345 March 10, 2003 April 1, 2003 May 1, 2003 $.345 June 10, 2003 July 1, 2003 July 31, 2003 $.345 September 10, 2003 October 1, 2003 - ----------------- ------------------- ------------------- --------------------- Electric Operations Electric Operations is comprised of the electric portion of SCE&G, South Carolina Generating Company, Inc. (GENCO) and South Carolina Fuel Company (Fuel Company). Changes in the electric operations sales margins were as follows:
------------------------------------------------------------------------------------------------------------------------- Third Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change ------------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------------- Operating revenues $429.0 $424.2 $4.8 1.1% $1,121.3 $1,075.3 $46.0 4.3% Less: Fuel used in generation 96.8 105.1 (8.3) (7.9%) 257.6 271.0 (13.4) (4.9%) Purchased power 12.8 7.3 5.5 75.3% 38.9 28.7 10.2 35.5% ------------------------------------------------------------------ --------------------------------- Margin $319.4 $311.8 $7.6 2.4% $824.8 $775.6 $49.2 6.3% =========================================================================================================================
Third Quarter 2003 vs 2002 Margin increased primarily due to the increase in retail electric base rates approved in January 2003 of $24.5 million partially offset by $18.5 million due to less favorable weather. Fuel used in generation decreased and purchased power increased due to planned plant outages. Year to Date 2003 vs 2002 Margin increased primarily due to the increase in retail electric base rates approved in January 2003 of $58.6 million and by $11.4 million due to customer growth and increased consumption. These increases were partially offset by $20.8 million due to the effects of less favorable weather. Fuel used in generation decreased and purchased power increased due to planned plant outages. Gas Distribution Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy. Changes in the gas distribution sales margins, including transactions with affiliates, were as follows:
- -------------------------------------------------------------------------------------------------------------------------- Third Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change - -------------------------------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------------------------------- Operating revenues $113.7 $85.7 $28.0 32.7% $602.6 $429.1 $173.5 40.4% Less: Gas purchased for resale 81.0 53.9 27.1 50.3% 414.7 254.9 159.8 62.7% - ------------------------------------------------------------------- ---------------------------------- Margin $32.7 $31.8 $0.9 2.8% $187.9 $174.2 $13.7 7.9% ==========================================================================================================================
Third Quarter 2003 vs 2002 Margin increased primarily due to customer growth and increased consumption of $2.5 million, partially offset by a decrease in industrial usage of $1.5 million primarily due to an unfavorable competitive position of natural gas relative to alternate fuels. Year to Date 2003 vs 2002 Margin increased primarily due to customer growth at PSNC Energy of 2.7% and at SCE&G of 1.3% and increased recovery of environmental remediation expenses of $1.7 million (offset in operations and maintenance), partially offset by a decrease in industrial usage of $3.8 million primarily due to an unfavorable competitive position of natural gas relative to alternate fuels. Gas Transmission Gas Transmission is comprised of the operations of SCPC. Changes in the gas transmission sales margins, including transactions with affiliates, were as follows:
- -------------------------------------------------------------------------------------------------------------------------- Third Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change - -------------------------------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------------------------------- Operating revenues $94.9 $105.3 $(10.4) (9.9%) $397.4 $344.3 $53.1 15.4% Less: Gas purchased for resale 84.2 92.2 (8.0) (8.7%) 362.6 319.1 43.5 13.6% - ------------------------------------------------------------------- ---------------------------------- ---------------------------------- Margin $10.7 $13.1 $(2.4) (18.3%) $34.8 $25.2 $9.6 38.1% ==========================================================================================================================
Third Quarter 2003 vs 2002 Margin decreased primarily due to an unfavorable competitive position of natural gas relative to alternate fuels and decreased demand for natural gas as a fuel for electric generation due to milder weather. Year to Date 2003 vs 2002 Margin increased primarily due to the favorable competitive position of natural gas relative to alternate fuels in the first quarter of $13.6 million, partially offset by the unfavorable competitive position of natural gas relative to alternate fuels in the second and third quarters of $4.0 million. ~~Retail Gas Marketing Retail Gas Marketing is comprised of SCANA Energy. Changes in Retail Gas Marketing revenues and net income (loss) were as follows:~~
- -------------------------------------------------------------------------------------------------------------------------- Third Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change - -------------------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------- Operating revenues $60.1 $46.4 $13.7 29.5% $320.3 $264.6 $55.7 21.1% Net income (loss) $0.1 $(3.5) 3.6 * $16.7 $9.9 $6.8 68.7% ========================================================================================================================== *Greater than 100%
Third Quarter 2003 vs 2002 Operating revenues increased primarily as a result of increased volumes and higher average retail prices. Net income increased primarily due to higher margins of $3.7 million and lower operating expenses of $0.5 million, partially offset by increased bad debt expense of $1.1 million. Year to Date 2003 vs 2002 Operating revenues increased primarily as a result of increased volumes and higher average retail prices. Net income increased primarily due to higher margins of $9.7 million, partially offset by increased bad debt expense of $1.8 million, increased interest expense of $0.6 million and higher operating expense of $0.8 million. Energy Marketing Energy Marketing is comprised of the Company's non-regulated marketing operations, excluding SCANA Energy. Changes in energy marketing operating revenues, including transactions with affiliates, and net income (loss) were as follows:
- ----------------------------------------------------------------------------------------------------------------------- Third Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change - ----------------------------------------------------------------------------------------------------------------------- ----------------------------------------------------- Operating revenues $106.8 $87.7 $19.1 21.8% $329.8 $238.2 $91.6 38.5% Net income (loss) $0.7 $(0.1) $0.8 * $(1.0) $(2.1) $1.1 53.6% ======================================================================================================================= *Greater than 100%
Third Quarter 2003 vs 2002 Operating revenues increased primarily as a result of the increase in commodity natural gas prices. Net income increased primarily due to lower bad debt expense of $5.3 million partially offset by higher operating expenses of $4.6 million. Year to Date 2003 vs 2002 Operating revenues increased primarily as a result of the increase in commodity natural gas prices. Net loss decreased primarily as a result of lower bad debt expense of $1.9 million and lower operating and interest expenses of $1.0 million, partially offset by lower margins of $1.9 million. Other Operating Expenses
Changes in other operating expenses were as follows: - ------------------------------------------------------------------------------------------------------------------------- Third Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change - ------------------------------------------------------------------------------------------------------------------------- Other operation and maintenance $134.8 $125.4 $9.4 7.5% $420.0 $383.3 $36.7 9.6% Depreciation and amortization 60.1 55.0 5.1 9.3% 180.3 163.4 16.9 10.3% Other taxes 34.9 31.6 3.3 10.4% 104.7 94.9 9.8 10.3% - ---------------------------------------------------------------------- -------------------------------- Total $229.8 $212.0 $17.8 8.4% $705.0 $641.6 $63.4 9.9% =========================================================================================================================
Third Quarter 2003 vs 2002 Other operation and maintenance expenses increased primarily due to reduced pension income of $0.7 million, increased labor and benefit costs of $4.5 million and increased bad debt expenses of $3.0 million. Depreciation and amortization increased due to normal net property changes. Other taxes increased primarily due to increased property taxes. Year to Date 2003 vs 2002 Other operation and maintenance expenses increased primarily due to reduced pension income of $9.8 million, increased labor and benefits costs of $13.2 million, increased amortization of environmental costs of $1.7 million, increased other operating expenses for electric generation and transmission of $1.0 million and increased bad debt expense of $5.4 million. Depreciation and amortization increased by $12.7 million due to normal net property changes and by $4.2 million due to the completion of the Urquhart Station repowering project in June 2002. Other taxes increased primarily due to increased property taxes. Other Income (Expense) Other income, including AFC, for the third quarter and year to date periods 2003 vs 2002, increased primarily due to changes related to the gain on sale of assets and investments and the impairment of investments as discussed at Earnings Per Share. Other income decreased due to a reduction in AFC due to completion of the Urquhart Station Repowering project in June 2002. In addition, in January 2003 the SCPSC issued an order allowing SCE&G to include all Jasper County Generating Station project expenditures as of December 31, 2002 and other construction work in progress expenditures as of June 30, 2002 in electric rate base. At the time the expenditures were included in rate base, AFC was no longer calculated on those amounts. These decreases were partially offset by increased AFC from subsequent Jasper County Generating Station project expenditures and the Lake Murray Dam Project. Interest Expense Third Quarter 2003 vs 2002 Interest expense decreased $3.0 million due to lower interest rates offset by $1.9 million due to increased debt and lower AFC. Year to Date 2003 vs 2002 Interest expense decreased $12.4 million due to lower interest rates offset by $11.7 million due to increased debt and lower AFC. Income Taxes Third Quarter 2003 vs 2002 Income taxes decreased primarily due to favorable income tax adjustments related to prior periods and reduced pre-tax income. Year to Date 2003 vs 2002 Income taxes increased primarily as a result of changes in Other Income (Expense) as discussed at Earnings Per Share, partially offset by reduced income tax expense due to favorable income tax adjustments related to prior periods. been properly claimed.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

All financial instruments held by the Company described below are held for purposes other than trading.

Interest rate ~~risk -~~ 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.
As of September 30, 2003 Expected Maturity Date - ------------------------ ---------------------- Millions of dollars There- Fair Liabilities 2003 2004 2005 2006 2007 After Total Value - --------------------------------------- -------- -------- --------- --------- --------- ---------- ---------- -------------- - --------------------------------------- -------- -------- --------- --------- --------- ---------- ---------- -------------- Long-Term Debt: Fixed Rate ($) 146.9 202.2 197.1 177.4 71.3 2,424.2 3,219.1 3,301.0 Average Fixed Interest Rate (%) 6.53 7.51 7.37 8.74 6.94 6.65 6.36 Variable Rate ($) 150.0 150.0 149.3 Average Variable Interest Rate (%) 1.74 1.74 Interest Rate Swaps: Pay Variable/Receive Fixed ($) 4.3 57.5 3.2 3.2 28.2 241.0 337.4 12.08 Average Pay Interest Rate (%) 7.06 5.86 4.33 4.33 4.33 2.81 3.54 Average Receive Interest Rate (%) 10.00 7.70 8.75 8.75 7.11 6.21 6.63

As of March 31, 2004		Expected Maturity Date
Millions of dollars Liabilities		2004	2005	2006	2007	2008	There- After	Total	Fair Value
Long-Term Debt:
Fixed Rate ($)		197.9	193.6	174.4	68.6	158.6	2,640.9	3,434.0	3,484.1
Average Fixed Interest Rate (%)		7.53	7.39	8.50	6.96	6.13	6.24	6.60
Variable Rate ($)				200.0				200.0	200.0
Average Variable Interest Rate (%)				1.57				1.57
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)		57.5	3.2	3.2	28.2	118.2	122.8	333.1	14.3
	Average Pay Interest Rate (%)	5.84	4.30	4.30	4.31	2.81	2.97	3.55
	Average Receive Interest Rate (%)	7.70	8.75	8.75	7.11	5.89	6.51	6.59

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, 2003~~March 31, 2004 the Company held investments in the ~~12%~~13% senior unsecured notes (due 2009) of a telecommunications company, the cost basis of which, including accrued interest, is approximately ~~$48~~$51.1 million. As these notes are not ~~actively~~broadly traded, determination of their fair value is not practicable. In June 2002 SCE&G entered into a parts availability agreement with a supplier whereby turbine and stator bar parts will be stored by SCE&G to be available when needed. The parts will remain the property of the supplier until such time as they are removed from storage by SCE&G and payment is made. SCE&G bears the risk of loss or repair for any part damaged while in storage and will pay an availability fee each quarter based on the daily available parts stored. In addition, SCE&G is obligated to purchase all remaining stored parts at the termination dates of the contract, June 2009 for the turbine parts and December 2006 for the stator bar parts. As such, SCE&G has recorded a liability in Other Long-Term Debt with an offsetting asset in Deferred Debits. At September 30, 2003 SCE&G had recorded $30.8 million for the turbine parts and $3.2 million for the stator bar parts.

Commodity price ~~risk -~~ 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.
Expected Maturity: Options Futures Contracts Purchased call Purchased put 2003 Long($) Short ($) (long) ($) (short) ($) Settlement Price (a) 4.98 4.96 Contract Amount 21.1 1.0 Strike Price (a) 5.56 5.40 Fair Value 19.9 0.8 Contract Amount 1.8 5.7 2004 Settlement Price (a) 5.06 5.13 Contract Amount 32.3 0.2 Strike Price (a) 5.13 5.50 Fair Value 31.4 0.2 Contract Amount 3.5 0.4 2005 Settlement Price (a) 4.71 - Contract Amount 3.4 - Strike Price (a) - - Fair Value 3.7 - Contract Amount - - 2006 Settlement Price (a) 4.84 - Contract Amount 0.5 - Strike Price (a) - - Fair Value 0.6 - Contract Amount - -
The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 6 of Notes to Condensed Consolidated Financial Statements. The NYMEX futures information above includes those financial positions of Energy Marketing, SCPC and PSNC Energy. Certain derivatives that SCPC utilizes to hedge its gas purchasing activities are recoverable through its weighted

Expected Maturity:

	Futures Contracts			Options
2004	Long ($)	Short ($)		Purchased call (long) ($)	Purchased put (short) ($)
Settlement Price^(a)	6.05	6.01
Contract Amount	16.5	2.4	Strike Price^(a)	4.86	—
Fair Value	20.0	2.6	Contract Amount	6.8	—
2005
Settlement Price^(a)	5.89	6.44
Contract Amount	5.3	0.2	Strike Price^(a)	—	—
Fair Value	6.5	0.2	Contract Amount	—	—
2006
Settlement Price^(a)	5.66	—
Contract Amount	0.5	—	Strike Price^(a)	—	—
Fair Value	0.7	—	Contract Amount	—	—

(a): Weighted average cost of gas calculation. SCPC's tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCPC's hedging activities are to be included in the PGA. The offset to the change in fair value of these derivatives is recorded as a current asset or liability. Beginning in January 2003, PSNC Energy initiated a hedging program for gas purchasing activities using NYMEX futures and options. PSNC Energy's tariffs include a provision for the recovery of actual gas costs incurred. PSNC Energy will include the offset to the change in fair value of derivatives acquired as part of its hedging program in deferred accounts for the over or under recovery of gas costs. In an October 2003 order, the North Carolina Utilities Commission (NCUC) declared the program was reasonable. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability.

Equity price ~~risk -~~ 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 ~~$94.8~~$40.4 million at ~~September 30, 2003.~~March 31, 2004. A temporary decline in value of ten percent would result in a ~~$9.5~~$4.0 million reduction in fair value and a corresponding adjustment, net of tax effect, to the related equity account for unrealized gains/losses, a component of Other Comprehensive Income (Loss). An other than temporary decline in value of ten percent would result in a ~~$9.5~~$4.0 million reduction in fair value and a corresponding adjustment to net income, net of tax effect.

Item 4. Controls and Procedures

As of ~~September 30, 2003~~March 31, 2004 an evaluation was performed under the supervision and with the participation of the Company's management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Company's management, including the CEO and CFO, concluded that as of ~~September 30, 2003~~March 31, 2004 the Company's disclosure controls and procedures were effective. There has been no change in the Company's internal control over financial reporting during the quarter ended ~~September 30, 2003~~March 31, 2004 that has materially affected or is reasonably likely to materially affect the Company's internal control over financial reporting.

SOUTH CAROLINA ELECTRIC & GAS COMPANY
FINANCIAL SECTION
Item 1. Financial Statements SOUTH CAROLINA ELECTRIC & GAS COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - ------------------------------------------------------------------------------ ------------------- ----------------------- September 30, December 31, Millions of dollars 2003 2002 - ------------------------------------------------------------------------------ ------------------- ----------------------- Assets Utility Plant: Electric $5,098 $4,934 Gas 453 439 Other 181 184 - ------------------------------------------------------------------------------ ------------------- ----------------------- Total 5,732 5,557 Accumulated depreciation and amortization (2,009) (1,912) - ------------------------------------------------------------------------------ ------------------- ----------------------- Total 3,723 3,645 Construction work in progress 877 604 Nuclear fuel, net of accumulated amortization 41 38 - ------------------------------------------------------------------------------ ------------------- ----------------------- Utility Plant, Net 4,641 4,287 - ------------------------------------------------------------------------------ ------------------- ----------------------- Nonutility Property and Investments, Net 25 25 - ------------------------------------------------------------------------------ ------------------- ----------------------- - ------------------------------------------------------------------------------ ------------------- ----------------------- Current Assets: Cash and temporary investments 25 56 Receivables, net 226 237 Receivables - affiliated companies 64 46 Inventories (at average cost): Fuel 27 48 Materials and supplies 52 53 Emission allowances 7 10 Prepayments 20 24 - ------------------------------------------------------------------------------ ------------------- ----------------------- Total Current Assets 421 474 - ------------------------------------------------------------------------------ ------------------- ----------------------- Deferred Debits: Environmental 12 18 Nuclear plant decommissioning - 87 Assets held in trust, net - nuclear decommissioning 35 - Pension asset, net 269 265 Due from affiliates - pension and postretirement benefits 20 18 Other regulatory assets 296 267 Other 146 103 - ------------------------------------------------------------------------------ ------------------- ----------------------- Total Deferred Debits 778 758 - ------------------------------------------------------------------------------ ------------------- ----------------------- Total $5,865 $5,544 ============================================================================== =================== ======================= - --------------------------------------------------------------------------------- ----------------- -------------------- September 30, December 31, Millions of dollars 2003 2002 - --------------------------------------------------------------------------------- ----------------- -------------------- Capitalization and Liabilities Stockholders' Investment: Common equity $2,028 $1,966 Preferred stock (Not subject to purchase or sinking funds) 106 106 - --------------------------------------------------------------------------------- ----------------- -------------------- Total Stockholders' Investment 2,134 2,072 Preferred Stock, net (Subject to purchase or sinking funds) 9 9 Company-Obligated Mandatorily Redeemable Preferred Securities of the Company's Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount of 7.55% Junior Subordinated Debentures of SCE&G - 50 Long-Term Debt, net 1,706 1,534 - --------------------------------------------------------------------------------- ----------------- -------------------- Total Capitalization 3,849 3,665 - --------------------------------------------------------------------------------- ----------------- -------------------- Current Liabilities: Short-term borrowings 196 178 Current portion of long-term debt 238 144 Accounts payable 82 124 Accounts payable - affiliated companies 63 77 Customer deposits 24 22 Taxes accrued 100 93 Interest accrued 35 31 Dividends declared 39 42 Deferred income taxes, net 4 12 Other 23 37 - --------------------------------------------------------------------------------- ----------------- -------------------- Total Current Liabilities 804 760 - --------------------------------------------------------------------------------- ----------------- -------------------- Deferred Credits: Deferred income taxes, net 650 610 Deferred investment tax credits 111 108 Reserve for nuclear plant decommissioning - 87 Asset retirement obligation - nuclear plant 116 - Due to affiliates - pension and postretirement benefits 15 17 Postretirement benefits 133 131 Regulatory liabilities 133 109 Other 54 57 - --------------------------------------------------------------------------------- ----------------- -------------------- Total Deferred Credits 1,212 1,119 - --------------------------------------------------------------------------------- ----------------- -------------------- Total $5,865 $5,544 ================================================================================= ================= ==================== See Notes to Condensed Consolidated Financial Statements. SOUTH CAROLINA ELECTRIC & GAS COMPANY CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - ---------------------------------------------------------------- -------------------------- ------------------------- Three Months Ended Nine Months Ended September 30, September 30, Millions of dollars 2003 2002 2003 2002 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Operating Revenues: Electric $430 $425 $1,125 $1,079 Gas 54 47 258 207 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Total Operating Revenues 484 472 1,383 1,286 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Operating Expenses: Fuel used in electric generation 78 86 218 217 Purchased power (including affiliated purchases) 42 36 107 111 Gas purchased for resale 44 36 194 148 Other operation and maintenance 93 89 296 269 Depreciation and amortization 47 43 142 126 Other taxes 30 27 90 81 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Total Operating Expenses 334 317 1,047 952 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Operating Income 150 155 336 334 Other Income, Including Allowance for Equity Funds Used During Construction of $5, $5, $13 and $16 9 9 24 28 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Income Before Interest Charges, Income Taxes and Preferred Stock Dividends 159 164 360 362 Interest Charges, Net of Allowance for Borrowed Funds Used During Construction of $3, $3, $7 and $10 30 30 97 87 Dividend Requirement of Company - Obligated Mandatorily Redeemable Preferred Securities - 1 2 3 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Income Before Income Taxes and Preferred Stock Dividends 129 133 261 272 Income Tax Expense 41 47 86 94 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Net Income 88 86 175 178 Preferred Stock Cash Dividends Declared (At stated rates) 2 2 6 6 - ---------------------------------------------------------------- ------------ ------------- ------------- ----------- Earnings Available for Common Stockholder $86 $84 $169 $172 ================================================================ ============ ============= ============= =========== See Notes to Condensed Consolidated Financial Statements. o 40 SOUTH CAROLINA ELECTRIC & GAS COMPANY CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - -------------------------------------------------------------------------------------------- ---------------------------- Nine Months Ended September 30, Millions of dollars 2003 2002 - -------------------------------------------------------------------------------------------- -------------- ------------- Cash Flows From Operating Activities: Net income $175 $178 Adjustments to reconcile net income to net cash provided from operating activities: Depreciation and amortization 141 127 Amortization of nuclear fuel 18 14 Allowance for funds used during construction (20) (26) Over (under) collections, fuel adjustment clauses 26 (14) Changes in certain assets and liabilities: (Increase) decrease in receivables, net (7) (27) (Increase) decrease in inventories 25 (7) (Increase) decrease in prepayments 4 (8) (Increase) decrease in pension asset (4) (20) (Increase) decrease in other regulatory assets (20) (1) Increase (decrease) in deferred income taxes, net 32 14 Increase (decrease) in regulatory liabilities 34 32 Increase (decrease) in postretirement benefits obligations 2 7 Increase (decrease) in accounts payable (56) (40) Increase (decrease) in taxes accrued 7 (11) Increase (decrease) in interest accrued 4 4 Changes in other assets 4 (15) Changes in other liabilities 8 3 - -------------------------------------------------------------------------------------------- ------------- -------------- Net Cash Provided From Operating Activities 373 210 - -------------------------------------------------------------------------------------------- ------------- -------------- Cash Flows From Investing Activities: Utility property additions and construction expenditures, net of AFC (451) (362) Proceeds from sales of assets - 1 Increase in nonutility property - (2) Increase in investments (11) (7) - -------------------------------------------------------------------------------------------- ------------- -------------- Net Cash Used For Investing Activities (462) (370) - -------------------------------------------------------------------------------------------- ------------- -------------- Cash Flows From Financing Activities: Proceeds: Issuance of First Mortgage Bonds 495 295 Capital contribution from parent 2 5 Repayments: Mortgage Bonds (250) (104) Pollution Control Bonds (6) - Other long-term debt (12) (3) SCE&G Trust 1 Preferred Securities (50) - Retirement of preferred stock - (1) Payment of deferred financing costs (21) - Dividends and distributions: Common stock (112) (113) Preferred stock (6) (6) Short-term borrowings, net 18 84 - -------------------------------------------------------------------------------------------- ------------- -------------- Net Cash Provided From Financing Activities 58 157 - -------------------------------------------------------------------------------------------- ------------- -------------- Net Decrease In Cash and Temporary Investments (31) (3) Cash and Temporary Investments, January 1 56 37 - -------------------------------------------------------------------------------------------- ------------- -------------- Cash and Temporary Investments, September 30 $25 $34 ============================================================================================ ============= ============== Supplemental Cash Flow Information: Cash paid for - Interest (net of capitalized interest of $7 and $10) $93 $82 - Income taxes 22 54

Item 1. Financial Statements

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

Millions of dollars			March 31, 2004			December 31, 2003
Assets
Utility Plant:
	Electric		$	5,616		$	5,558
	Gas			459			456
	Common			196			193

	Total			6,271			6,207
	Accumulated depreciation and amortization			(1,937	)		(1,907	)

	Total			4,334			4,300
	Construction work in progress			989			951
	Nuclear fuel, net of accumulated amortization			36			42

	Utility Plant, Net			5,359			5,293

Nonutility Property and Investments, Net				26			25

Current Assets:
	Cash and temporary investments			79			56
	Receivables, net			230			238
	Receivables—affiliated companies			42			61
	Inventories (at average cost):
		Fuel		30			35
		Materials and supplies		56			54
		Emission allowances		13			6
	Prepayments			25			20
	Deferred income taxes, net			4			—

	Total Current Assets			479			470

Deferred Debits:
	Environmental			10			11
	Assets held in trust, net—nuclear decommissioning			46			44
	Pension asset, net			274			270
	Due from affiliates—pension and postretirement benefits			21			20
	Other regulatory assets			310			333
	Other			139			145

	Total Deferred Debits			800			823

Total			$	6,664		$	6,611

Millions of dollars		March 31, 2004		December 31, 2003
Capitalization and Liabilities
Shareholders' Investment:
	Common equity	$	2,059	$	2,043
	Preferred stock (Not subject to purchase or sinking funds)		106		106

	Total Shareholders' Investment		2,165		2,149
Preferred Stock, net (Subject to purchase or sinking funds)			9		9
Long-Term Debt, net			2,110		2,010

Total Capitalization			4,284		4,168

Minority Interest			75		100

Current Liabilities:
	Short-term borrowings		191		140
	Current portion of long-term debt		142		142
	Accounts payable		93		104
	Accounts payable—affiliated companies		91		134
	Customer deposits		25		25
	Taxes accrued		48		101
	Interest accrued		40		39
	Dividends declared		38		43
	Deferred income taxes, net		—		8
	Other		24		34

	Total Current Liabilities		692		770

Deferred Credits:
	Deferred income taxes, net		720		707
	Deferred investment tax credits		114		114
	Asset retirement obligation—nuclear plant		119		118
	Due to affiliates—pension and postretirement benefits		15		15
	Postretirement benefits		136		135
	Regulatory liabilities		446		429
	Other		63		55

	Total Deferred Credits		1,613		1,573

Commitments and Contingencies			—		—

Total		$	6,664	$	6,611

See Notes to Condensed Consolidated Financial Statements.

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

		Three Months Ended March 31,
Millions of dollars		Three Months Ended March 31,
Millions of dollars		2004		2003
Operating Revenues:
	Electric	$	381	$	337
	Gas		146		140

	Total Operating Revenues		527		477

Operating Expenses:
	Fuel used in electric generation		95		81
	Purchased power (including affiliated purchases)		13		10
	Gas purchased for resale		111		100
	Other operation and maintenance		108		104
	Depreciation and amortization		52		49
	Other taxes		35		31

	Total Operating Expenses		414		375

Operating Income			113		102
Other Income, Including Allowance for Equity Funds Used During Construction of $5 and $4			6		7

Income Before Interest Charges, Minority Interest, Income Taxes and Preferred Stock Dividends			119		109
Interest Charges, Net of Allowance for Borrowed Funds Used During Construction of $3 and $2			35		34
Dividend Requirement of Company—Obligated Mandatorily Redeemable Preferred Securities			—		1

Income Before Minority Interest, Income Taxes and Preferred Stock Dividends			84		74
Minority Interest			2		2

Income Before Income Taxes and Preferred Stock Dividends			82		72
Income Tax Expense			28		25

Net Income			54		47
Preferred Stock Cash Dividends Declared (At stated rates)			2		2

Earnings Available for Common Shareholder		$	52	$	45

See Notes to Condensed Consolidated Financial Statements.

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

				Three Months Ended March 31,
Millions of dollars				Three Months Ended March 31,
Millions of dollars				2004			2003
Cash Flows From Operating Activities:
	Net income			$	54		$	47
	Adjustments to reconcile net income to net cash provided from operating activities:
		Minority interest			2			2
		Depreciation and amortization			52			49
		Amortization of nuclear fuel			6			6
		Allowance for funds used during construction			(8	)		(6	)
		Over collections, fuel adjustment clauses			32			22
		Changes in certain assets and liabilities:
			(Increase) decrease in receivables, net		27			(1	)
			(Increase) decrease in inventories		(4	)		15
			(Increase) decrease in prepayments		(5	)		3
			(Increase) decrease in pension asset		(4	)		(1	)
			(Increase) decrease in other regulatory assets		2			—
			Increase (decrease) in deferred income taxes, net		1			(1	)
			Increase (decrease) in regulatory liabilities		4			9
			Increase (decrease) in postretirement benefits obligations		1			3
			Increase (decrease) in accounts payable		(54	)		(22	)
			Increase (decrease) in taxes accrued		(53	)		(41	)
			Increase (decrease) in interest accrued		1			5
		Changes in other assets			(1	)		(21	)
		Changes in other liabilities			—			(2	)

	Net Cash Provided From Operating Activities				53			66

Cash Flows From Investing Activities:
	Utility property additions and construction expenditures, net of AFC				(107	)		(155	)
	Increase in nonutility property				(1	)		—
	Investments in affiliates				(3	)		(4	)

	Net Cash Used For Investing Activities				(111	)		(159	)

Cash Flows From Financing Activities:
	Proceeds:
		Issuance of First Mortgage Bonds			—			198
		Issuance of notes			100			—
	Dividends and distributions:
		Common stock			(41	)		(40	)
		Preferred stock			(2	)		(2	)
		Distribution to parent			(27	)		—
	Short-term borrowings, net				51			(64	)

	Net Cash Provided From Financing Activities				81			92

Net Increase (Decrease) In Cash and Temporary Investments					23			(1	)
Cash and Temporary Investments, January 1					56			23

Cash and Temporary Investments, March 31				$	79		$	22

Supplemental Cash Flow Information:
	Cash paid for—Interest (net of capitalized interest of $3 and $2)			$	35		$	30
	—Income taxes				—			—

See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ~~September 30, 2003~~
March 31, 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 (the Company) Annual Report on Form 10-K for the year ended December 31, ~~2002.~~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. The Company 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 the Company, 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 $336 million in net assets reflected in the condensed consolidated balance sheet for March 31, 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 the Company under the terms of a power purchase and related agreement. Substantially all of GENCO's property (carrying value of approximately $75 million) serves as collateral for its long-term borrowings.

B. Basis of Accounting

$320 million and ~~$133~~$446 million of regulatory assets (including environmental) and liabilities, respectively, as shown below. September 30, December 31, Millions of dollars 2003 2002 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Accumulated deferred income taxes, net $86 $86 Under-collections - electric fuelrespectively. Information relating to regulatory assets and gas cost adjustment clauses, net 24 50 Deferred environmental remediation costs 12 18 Asset retirement obligation - nuclear decommissioning 43 - Deferred non-conventional fuel tax benefits, net (59) (40) Storm damage reserve (36) (32) Franchise agreements 62 65 Other 43 29 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Total $175 $176 ================================================================================liabilities follows.

Millions of dollars	March 31, 2004			December 31, 2003
Accumulated deferred income taxes, net	$	103		$	104
Under-(over-)collections—electric fuel and gas cost adjustment clauses, net		7			39
Deferred environmental remediation costs		10			11
Asset retirement obligation—nuclear decommissioning		47			48
Deferred non-conventional fuel tax benefits, net		(74	)		(67	)
Storm damage reserve		(34	)		(37	)
Franchise agreements		60			62
Non-legal asset retirement obligations		(270	)		(265	)
Other		25			20

Total	$	(126	)	$	(85	)

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

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

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

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 the Company. However, ultimate recovery is subject to SCPSC approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company's results of operations, liquidity or financial position in the period the write-off would be recorded. B. New Accounting Standards The Company adopted SFAS 143 effective January 1, 2003. SFAS 143 applies to legal obligations associated with the retirement of tangible long-lived assets (ARO) and requires the Company to recognize, as a liability, the fair value of an ARO in the period in which it is incurred and to accrete the liability to its present value in future periods. As of December 31, 2002, prior to the adoption of SFAS 143, the Company carried deferred debits and deferred credits each totaling approximately $87 million related to the decommissioning and dismantling of Summer Station and the funding thereof. Effective January 1, 2003, in connection with the measurement of the ARO upon the adoption of SFAS 143, the amounts reflected within these regulatory assets and liabilities were recharacterized. The following table presents such recharacterized amounts related to the decommissioning obligation and the funding thereof as recorded in the condensed consolidated balance sheet as of September 30, 2003, and the pro forma amounts that would have been recorded as of December 31, 2002 and 2001 had SFAS 143 been adopted at the beginning of 2001. As of September 30, December 31, December 31, Millions of dollars 2003 2002 2001 - ------------------- Actual Proforma Proforma Assets: Within electric plant $40 $40 $40 Within accumulated depreciation (13) (13) (12) Assets held in trust (net) - nuclear decommissioning 35 39 35 Within other regulatory assets 54 45 42 -------------- --------------- ------------- -------------- --------------- ------------- Total $116 $111 $105 ============== =============== ============= ============== =============== ============= Liabilities: Asset retirement obligation - nuclear plant decommissioning $116 $111 $105 ================ =============== =========== Proforma net income for periods prior to the adoption of SFAS 143 would not differ from amounts actually recorded during these periods. The Company believes that there is legal uncertainty as to the existence of environmental obligations associated with certain transmission and distribution properties. The Company believes that any ARO related to this type of property would be insignificant and, due to the indeterminate life of the related assets, an ARO could not be reasonably estimated. The Company adopted SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," effective January 1, 2003. The provisions of SFAS 145, among other things, discontinue treatment of gains or losses from the early extinguishment of debt as extraordinary items unless such early extinguishment meets the criteria of Accounting Principles Board Opinion (APB) 30. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 145. The Company adopted SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," effective January 1, 2003. This statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 146. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" was issued in May 2003. SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). SFAS 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 150.

C. Affiliated Transactions

The Company has entered into agreements with certain affiliates to purchase gas for resale to its distribution customers and to purchase electric energy. The Company purchases all of its natural gas requirements from South Carolina Pipeline Corporation (SCPC). The Company had approximately ~~$15.8~~$26.8 million and ~~$29.6~~$39.5 million payable to SCPC for such gas purchases at ~~September 30, 2003~~March 31, 2004 and December 31, 2002, respectively. The Company purchases all of the electric generation of Williams Station, which is owned by South Carolina Generating Company (GENCO), under a unit power sales agreement. The Company had approximately $8.7 million and $9.0 million, payable to GENCO for unit power purchases at September 30, 2003 and December 31, 2002, respectively. Such unit power purchases, which are included in "Purchased power", amounted to approximately $28.9 million and $68.2 million for the three and nine months ended September 30, 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 ~~$15.4~~$17.8 million and ~~$8.5~~$13.4 million at ~~September 30, 2003~~March 31, 2004 and December 31, ~~2002,~~2003, respectively. The Company had recorded as payables to these affiliated companies ~~for these investments~~ approximately ~~$14.3~~$15.6 million and ~~$8.0~~$12.2 million at ~~September 30, 2003~~March 31, 2004 and December 31, ~~2002,~~2003, respectively.

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 March 31 (Millions of dollars)	Pension Benefits
Three months ended March 31 (Millions of dollars)	2004			2003			2004			2003
Service cost	$	2.8		$	2.6		$	0.8		$	1.3
Interest cost		9.1			9.5			2.9			3.8
Expected return on assets		(17.7	)		(15.0	)		—			—
Prior service cost amortization		1.6			1.6			0.2			0.8
Transition obligation amortization		0.2			0.2			0.3			0.3
Actuarial (gain) loss		—			0.5			0.5			0.2
Amount attributable to company affiliates		(0.4	)		(0.5	)		(0.9	)		(1.2	)

Net periodic benefit (income) cost	$	(4.4	)	$	(1.1	)	$	3.8		$	5.2

E. Reclassifications

Certain amounts from prior periods have been reclassified to conform with the presentation adopted for ~~2003.~~ 2004.

2. RATE AND OTHER REGULATORY MATTERS

Electric In January 2003 the SCPSC issued an order granting the Company a composite increase in retail electric rates of 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for the Company's Cope Generating Station. Under the plan, based on the level of revenues and operating expenses, the Company may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.

In January 2003, in conjunction with the approval of ~~the above~~a retail rate increase, the SCPSC approved the Company's request to reduce the fuel component to 1.678 cents per KWh. This reduction was effective for service rendered on and after February 1, 2003. In April 2003 the SCPSC issued an order approving the Company's request to maintain the fuel cost component of rates at 1.678 cents per KWh, effective May 1, 2003. The SCPSC also reaffirmed the prudence of the Company's purchasing practices and recognized the efficiency of the Company's electric generating plants; however, it deferred action on the recovery of certain purchased power costs pending the resolution of the appeal ~~discussed below.~~of the SCPSC's May 2002 order. In May 2002 the SCPSC ~~issued an order approving~~approved the Company's request to increase the fuel component of rates charged to electric customers, ~~from 1.579 cents per KWh to 1.722 cents per KWh. The increase~~which reflected higher fuel costs projected for

the period May 2002 through April 2003. The increase also provided continued recovery for under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of the Company's base load generating plants in winter ~~2000-2001. The new rates were effective as of the first billing cycle in May 2002.~~2000–2001. The Consumer Advocate of South Carolina (Consumer Advocate) appealed to the South Carolina Circuit Court (Circuit Court) the portion of the SCPSC's order related to the recovery of certain purchased power costs. The ~~appeal is still pending.~~ Circuit Court ruled that the current fuel clause only provides for the recovery of the fuel costs included in purchased power and not the total cost of the power purchased. The Circuit Court remanded the case to the SCPSC for final disposition. In April 2004 the SCPSC approved a stipulation agreement between the Consumer Advocate and SCE&G whereby SCE&G would be allowed to defer for recovery in a future rate proceeding the portion of the purchased power costs not allowed to be recovered through the fuel clause.

Gas

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

The Company's cost of gas component in effect during the period January 1, ~~2002~~2003 through ~~September 30, 2003~~March 31, 2004 was as follows: Rate Per Therm Effective Date Rate Per Therm Effective Date $.728 January-February 2003 $.596 January-October 2002 $.928 March-September 2003 $.728 November-December 2002 On October 28, 2003, as part of the annual review of gas costs, the SCPSC approved the Company's request to decrease the cost of gas component from $.928 per therm to $.867 per therm effective with the first billing cycle in November 2003.

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

The SCPSC allows the Company to recover, through a billing surcharge to its gas customers, the costs of environmental cleanup at the sites of former ~~manufactured gas plants (MGPs).~~MGPs. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for the Company's gas operations that had previously been recorded in deferred debits. In October 2003, as a result of the annual review, the SCPSC approved the Company's request to reduce the billing surcharge from 3.0 cents per therm to ~~2.2~~0.8 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2009, of the balance remaining at ~~September 30, 2003~~March 31, 2004 of ~~$11.6~~$9.8 million.

3. LONG-TERM DEBT

On ~~January 23, 2003 the Company~~February 11, 2004 GENCO issued ~~$200~~$100 million of ~~First Mortgage Bonds having an annual~~senior secured promissory notes maturing February 1, 2024 and bearing a fixed interest rate of ~~5.80% and maturing on January 15, 2033. The proceeds~~5.49%. Proceeds from ~~the sale of these bonds~~this issuance were used to ~~reduce short-term debt~~support GENCO's construction program and to repay intercompany advances borrowed for general corporate purposes. On May 21, 2003 the Company issued $300 million First Mortgage Bonds having an annual interest rate of 5.30% and maturing on May 15, 2033. The Company used the net proceeds from the sale of these bonds and certain other Company funds to redeem its $100 million principal amount of 7.625% First Mortgage Bonds due June 1, 2023, its $150 million principal amount of 7.50% First Mortgage Bonds due June 15, 2023 and its Junior Subordinated Debentures which effected the redemption of $50 million aggregate amount of 7.55% Trust Preferred Securities, Series A, issued by SCE&G Trust I. In anticipation of the issuance of debt, the Company also uses interest rate lock or similar agreements to manage interest rate risks. Payments received or made upon termination of such agreements are recorded within other deferred debits on the balance sheet and are amortized to interest expense over the term of the underlying debt. In connection with the issuance of First Mortgage Bonds in May 2003, the Company paid approximately $11.9 million upon the termination of a treasury lock agreement. that purpose.

4. RETAINED EARNINGS

The Company'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, 2003~~March 31, 2004 approximately ~~$43.4~~$45.3 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock.

5. COMMITMENTS AND CONTINGENCIES

Reference is made to Note ~~11 of Notes~~10 to ~~Consolidated Financial Statements~~the consolidated financial statements appearing in the Company's Annual Report on Form 10-K for the year ended December 31, ~~2002.~~2003. Commitments and Contingencies at ~~September 30, 2003~~March 31, 2004 include the following:

A. Lake Murray Dam Reinforcement

In October 1999 the United States Federal Energy Regulatory Commission (FERC) mandated that the Company reinforce its Lake Murray ~~dam~~Dam in order to comply with new federal safety ~~standards and maintain the lake in case of an extreme earthquake.~~standards. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost approximately $275 million and be completed in 2005. Costs incurred through ~~September 30, 2003~~March 31, 2004 totaled approximately ~~$126~~$192 million.

B. Nuclear Insurance

The Price-Anderson Indemnification Act, which deals with public liability for a nuclear incident, currently establishes the liability limit for third-party claims associated with any nuclear incident at ~~$10.9~~$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. The Company'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. ~~The~~

The Company 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, the Company'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 the Company's rates would not recover the cost of any purchased replacement power, the Company will retain the risk of loss as a self-insurer. The Company has no reason to anticipate a serious nuclear incident at Summer Station. If such an incident were to occur, it would have a material adverse impact on the Company's results of operations, cash flows and financial position.

C. Environmental

At the Company, site assessment and cleanup costs are deferred and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled ~~$11.6~~$9.8 million at ~~September 30, 2003.~~March 31, 2004. The deferral includes the estimated costs associated with the following matters.

The Company owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for benzene contamination in the intermediate aquifer on surrounding properties. SCE&G anticipates that the remaining remediation activities will be completed by the end of 2004, with certain monitoring and retreatment activities continuing until 2007. As of ~~September 30, 2003,~~March 31, 2004, the Company has spent approximately ~~$19.6~~$19.8 million to remediate the Calhoun Park ~~site. Total remediation costs are estimated~~site and expects to ~~be $21.9~~spend an additional $2 million.

The Company owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by ~~DHEC. In addition, in March 2003~~ the Company signed a consent agreement with DHEC related to a site formerly owned by the Company. The site contained residue material that was moved from the Columbia MGP. The removal action for this site has been completed.South Carolina Department of Health and Environmental Control (DHEC). The Company is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. The Company anticipates that major remediation activities for the three owned sites will be completed before 2006. As of ~~September 30, 2003,~~March 31, 2004, the Company has spent approximately ~~$3.9~~$3.1 million related to these ~~three~~ sites, and expects to spend an additional ~~$5.2~~$4.9 million. ~~Total remediation costs are estimated to be $9.1 million~~

D. ~~Parts Availability Agreement In June 2002~~Claims and Litigation

On August 21, 2003, the Company ~~entered into~~was served as a ~~parts availability agreement with~~co-defendant in a ~~supplier whereby turbine~~purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and ~~stator bar parts~~South Carolina Electric & Gas Company, in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. The plaintiffs are seeking damages for the alleged improper use of electric transmission easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to non-utility third parties or telecommunication companies for other than the electric utilities' internal use along the electric transmission line right-of-way constitutes a trespass. The Company is confident of the propriety of its actions and intends to mount a vigorous defense. The Company further believes that the resolution of these claims will ~~be stored~~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 the Company by the State of South Carolina alleging that the Company violated the Unfair Trade Practices Act by charging municipal franchise fees to ~~be available when needed.~~some customers residing outside a municipality's limits. The ~~parts will remain~~complaint also alleges that the ~~property~~Company failed to obey, observe, or comply with the lawful order of the ~~supplier until such time as they~~SCPSC by charging franchise fees to those not residing in a municipality. The complaint seeks restitution to all affected customers and penalties up to $5,000 for each separate violation. The Company is confident of the reasonableness of its actions and intends to mount a vigorous defense. The allegations contained in the complaint are ~~removed from storage by~~the subject of a similar lawsuit that was filed and served on the Company, for which a Motion to Dismiss is pending. The allegations are also the subject of a purported class action lawsuit filed on or about December 12, 2003 against Duke Energy Corporation, Progress Energy Services Company and ~~payment is made.~~the Company. The Company ~~bears~~further believes that the ~~risk~~resolution of ~~loss~~these actions will not have a material adverse impact on its results of operations, cash flows or ~~repair for any part damaged while in storage and will pay an availability fee each quarter based on the daily available parts stored.~~financial condition. In addition, the Company ~~is obligated~~filed a petition with the SCPSC on October 23, 2003 pursuant to ~~purchase all remaining parts at~~S. C. Code Ann. R.103-836. The petition requests that the ~~termination dates~~SCPSC exercise its jurisdiction to investigate the operation of the ~~contract, June 2009 for~~municipal franchise fee collection requirements applicable to the ~~turbine parts~~Company's electric and ~~December 2006 for~~gas service, to approve the ~~stator bar stored parts. As~~Company's efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation which the SCPSC deems just and proper to regulate the franchise fee collection process.

The Company ~~has recorded a liability~~is also engaged in ~~Other Long-Term Debt with an offsetting asset in Deferred Debits. At September 30, 2003~~various other claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the ~~Company had recorded $30.8 million for the turbine parts and $3.2 million for the stator bar parts.~~ 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. ~~Accumulated depreciation is not assignable to Electric Operations and Gas Distribution segments; therefore, it is reflected as an adjustment to arrive at the consolidated total assets.~~ Intersegment revenues were not significant.
Disclosure of Reportable Segments (Millions of Dollars) Three Months Ended September 30, 2003 2002 - ------------------------------- ---------------------------- --------------------------- - ------------------------------- ----------- ---------------- External Operating External Operating Revenue Income (Loss) Revenue Income (Loss) - ------------------------------- ----------- ---------------- ------------ -------------- ------------ -------------- Electric Operations $430 $158 $425 $162 Gas Distribution 54 (8) 47 (6) Adjustments/Eliminations - - - (1) - ------------------------------- ----------- ---------------- ------------ -------------- - ------------------------------- ----------- ---------------- ------------ -------------- Consolidated Total $484 $150 $472 $155 =============================== =========== ================ ============ ============== Nine Months Ended September 30, 2003 2002 - ----------------------------- ---------- -------------- ---------- ------------ -------------- ----------- External Operating Segment External Operating Segment Revenue Income (Loss) Assets Revenue Income (Loss) Assets - ----------------------------- ---------- -------------- ---------- ------------ -------------- ----------- Electric Operations $1,125 $332 $5,991 $1,079 $329 $5,414 Gas Distribution 258 5 457 207 6 440 All Other - - - 4 - - Adjustments/Eliminations (1) - (1) (554) - (583) - ----------------------------- ---------- -------------- ---------- ------------ -------------- ----------- - ----------------------------- ---------- -------------- ---------- ------------ -------------- ----------- Consolidated Total $1,383 $336 $5,865 $1,286 $334 $5,304 ============================= ========== ============== ========== ============ ============== ===========
~~7. SUBSEQUENT EVENT On November 6, 2003 the Company issued $250 million First Mortgage Bonds having an annual interest rate~~ of ~~5.25% and maturing on November 1, 2018. The Company will use the net proceeds from the sale~~Reportable Segments
(Millions of these bonds for the payment at maturity of the Company's $100 million principal amount of 6.25% First Mortgage Bonds due December 15, 2003, for repayment of short-term debt primarily incurred as a result of the Company's construction program and for general corporate purposes. Dollars)

	2004						2003
Three Months Ended March 31,	External Revenue		Operating Income		Segment Assets		External Revenue		Operating Income		Segment Assets
Electric Operations	$	381	$	97	$	5,080	$	337	$	84	$	4,587
Gas Distribution		146		16		325		140		18		315
Adjustments/Eliminations		—		—		1,259		—		—		1,156

Consolidated Total	$	527	$	113	$	6,664	$	477	$	102	$	6,058

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

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

The following discussion should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in South Carolina Electric & Gas Company's (SCE&G) Annual Report on Form 10-K for the year ended December 31, ~~2002.~~2003.

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

Electric Operations

In ~~South Carolina electric restructuring efforts remain stalled,~~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 ~~state legislature adjourned for~~Task Force believes would improve reliability of North America's interconnected bulk power system (the grid). Full implementation of the ~~year without considering electric restructuring legislation. At~~Blackout Report's recommendations would require a number of actions by legislative, regulatory and industry participants. However, the ~~federal level, energy legislation~~Blackout Report asserts as its single most important recommendation that the U.S. Congress should enact the reliability provisions contained in the Energy Bill, different versions of which passed ~~both houses of Congress in 2003, though significant differences exist between~~ the House and Senate ~~versions. Some~~in 2003 but have stalled in conference committee. Various provisions of the ~~more stringent provisions of this~~Energy Bill related to electric reliability are being resubmitted as separate legislation ~~either currently included or expected to be debated in conference committee,~~(reliability legislation). It is anticipated that any reliability legislation, if passed, would ~~require that one percent~~make reliability standards mandatory and enforceable with penalties for non-compliance and would strengthen the role of the electric energy sold by retail electric suppliers, beginning in 2005, escalating to ten percent by 2020, be generated from renewable energy resources. Renewable energy resources, as defined in the legislation, may exclude hydroelectric generation. Substantial penalties would be levied for failure to comply. Electric cooperatives and municipal utilities would be exempt from these requirements. In addition, largely in response to the August 2003 blackout in eight northern states and parts of Canada, the energy legislation being considered includes several provisions to develop and enforce reliability standards for high-voltage transmission systems and to expedite construction of transmission lines. SCE&G cannot predict whether such legislation will be enacted, and if it is, the conditions it would impose on utilities. In July 2002 the United StatesU.S. Federal Energy Regulatory Commission (FERC) ~~issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design (SMD) which proposed sweeping changes~~, enabling it to enact regulatory initiatives that would significantly change the country's existing regulatory framework governing transmission, open access and energy markets and would attempt, in large measure, to standardize the national energy market. The Company cannot predict whether Congress will enact reliability legislation or the extent to which the other recommendations contained in the Blackout Report will be implemented. If implemented, such legislation could have a significant impact on SCE&G's access to or cost of power for its native load customers and on SCE&G's marketing of power outside of its service territory.

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

Net Income

Net income for the periods ended March 31, 2004 and 2003 was as follows:

	First Quarter
Millions of dollars	First Quarter
Millions of dollars	2004		2003
Net income	$	53.8	$	47.0

Net income increased due to higher electric margins of $16.6 million and a ~~"white paper" regarding SMD which describes how the final SMD rule being considered would differ from the NOPR. SCE&G is currently evaluating FERC's actions to determine potential effects~~reduction of preferred dividend requirements of $0.9 million, partially offset by lower gas margins of $3.1 million, higher operation and maintenance expense of $3.1 million, higher depreciation expense of $1.6 million, higher property taxes of $2.4 million and higher interest expense of $0.7 million.

Pension Income

Pension income was recorded on SCE&G's ~~operations. Additional directives from FERC are expected, and would likely be significantly influenced by~~financial statements as follows:

		First Quarter
Millions of dollars		First Quarter
Millions of dollars		2004		2003
Income Statement Impact:
	Reduction in (component of) employee benefit costs	$	1.4	$	(0.7	)
	Other income		2.5		2.0
Balance Sheet Impact:
	Reduction in (component of) capital expenditures		0.4		(0.2	)
	Component of amount due to Summer Station co-owner		0.1		—

Total Pension Income		$	4.4	$	1.1

For the ~~energy legislation discussed~~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 pension income in the ~~preceding paragraph.~~ first quarter of 2004 increased compared to the corresponding period in 2003 primarily as a result of a more favorable investment market.

Allowance for Funds Used During Construction (AFC)

AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. SCE&G includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. The increase in AFC for the three months ended March 31, 2004 is primarily due to construction expenditures related to the Jasper County Generating Station Project and the Lake Murray Dam Project (see discussion at CAPITAL PROJECTS).

Dividends Declared

SCE&G and GENCO's Board of Directors has 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

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:

	First Quarter
Millions of dollars	2004		% Change	2003
Operating Revenues	$	381.1	13.0%	$	337.4
Less: Fuel used in generation		95.4	18.1%		80.8
Purchased power		12.7	21.0%		10.5

Margin	$	273.0	10.9%	$	246.1

Margin increased primarily due to increased retail electric base rates that went into effect in February 2003 for a total impact of $7.1 million, an additional $3.2 million due to favorable weather, $14.6 million from off-system sales and $2.0 million due to customer growth and consumption.

Gas Distribution

Gas Distribution ~~Natural gas competes~~is comprised of the local distribution operations of SCE&G. Gas distribution sales margins (including transactions with ~~electricity, propane~~affiliates) were as follows:

	First Quarter
Millions of dollars	First Quarter
Millions of dollars	2004		% Change	2003
Operating Revenues	$	145.7	4.0%	$	140.1
Less: Gas purchased for resale		110.8	10.6%		100.2

Margin	$	34.9	(12.5)%	$	39.9

Margin decreased primarily due to decreased recovery of environmental remediation expenses of $3.2 million (offset in operations and ~~heating oil to serve the heating~~maintenance) and to a lesser extent, other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an ~~alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either~~unfavorable competitive position of natural gas ~~or of~~relative to alternate fuels of $1.9 million.

Other Operating Expenses

Other operating expenses were as follows:

	First Quarter
Millions of dollars	2004		% Change	2003
Other operation and maintenance	$	108.7	4.8%	$	103.7
Depreciation and amortization		51.9	5.3%		49.3
Other taxes		35.0	12.5%		31.1

Total	$	195.6	6.3%	$	184.1

Other operation and maintenance expenses increased primarily due ~~either~~ to ~~production or delivery disruptions or~~increased labor and benefit costs of $2.4 million, 2004 winter storm restoration expenses of $2.5 million and increased expenses at electric generation plants of $3.4 million, partially offset by decreased recovery of environmental remediation expenses of $3.2 million (offset in gas margin) and increased pension income of $2.1 million. Depreciation and amortization expense increased primarily due to normal net property changes. Other taxes increased primarily due to increased property taxes.

Other Income

Other income, including AFC, decreased primarily due to reduced other ~~factors, will affect price~~non-operating income partially offset by an increase in AFC due to construction expenditures related to the Jasper County Generation Station Project and ~~impact SCE&G's ability~~the Lake Murray Dam Project.

Interest Expense

Interest expense increased by $3.9 million due to ~~retain large commercial~~increased long-term debt partially offset by $2.1 million due to lower interest rates and ~~industrial customers.~~ by $1.0 million due to increased AFC.

Income Taxes

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

LIQUIDITY AND CAPITAL RESOURCES

SCE&G anticipates that its contractual cash obligations will be met through internally generated funds and the incurrence of additional short-term and long-term indebtedness. SCE&G expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future. SCE&G's ratio of earnings to fixed charges for the 12 months ended March 31, 2004 was 3.07.

SCE&G's cash requirements arise primarily from its operational needs, funding its construction programs and payment of dividends to SCANA. The ability of SCE&G to replace existing plant investment, as well as to expand to meet future demand for electricity and gas, will depend upon its ability to attract the necessary financial capital on reasonable terms. SCE&G recovers the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and SCE&G continues its ongoing construction program, SCE&G expects to seek increases in rates. SCE&G's future financial position and results of operations will be affected by its ability to obtain adequate and timely rate and other regulatory relief, if requested. In January 2003 the Public Service Commission of South Carolina (SCPSC) issued an order granting SCE&G a composite increase in retail electric rates of 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, based on the level of revenues and operating expenses, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually without the approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.

The following table summarizes how SCE&G generated and used funds for property additions and construction expenditures during the ~~nine~~three months ended ~~September 30, 2003~~March 31, 2004 and 2002: - ------------------------------------------------------------------------------- Nine Months Ended September 30, Millions2003:

	Three Months Ended March 31,
Millions of dollars	Three Months Ended March 31,
Millions of dollars	2004			2003
Net cash provided from operating activities	$	53		$	66
Net cash provided from financing activities		81			92
Funds used for investments		(3	)		(4	)
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	$	107		$	155
Funds used for nonutility property additions		1			—

SCE&G intends to file an electric rate case with the SCPSC in the summer of dollars 2003 2002 - -------------------------------------------------------------------- ---------- Net cash provided from operating activities $373 $210 Net cash provided from financing activities 58 157 Cash provided from sale2004 requesting, among other things, recovery of ~~assets - 1 Funds used for investments (11) (7) Cash and temporary cash investments available~~capital expenditures related to the generating facility in Jasper County, South Carolina. This filing will also include SCE&G's plan to use synthetic fuel tax credits to offset construction costs of SCE&G's reinforcement dam at Lake Murray. The SCPSC would be expected to render its decision on the ~~beginning~~filing within six months of the period 56 37 Funds used for utility property additions and construction expenditures, net of noncash allowance for funds used during construction $(451) $(362) Funds used for nonutility property additions - (2) SCE&G expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the next 12 months and for the foreseeable future. SCE&G's ratio of earnings to fixed charges for the 12 months ended September 30, 2003 was 3.29. rate application being filed.

CAPITAL TRANSACTIONS

On ~~January 23, 2003 SCE&G~~February 11, 2004 GENCO issued ~~$200~~$100 million of ~~First Mortgage Bonds having an annual~~senior secured promissory notes maturing February 1, 2024 and bearing a fixed interest rate of ~~5.80% and maturing January 15, 2033. The proceeds~~5.49%. Proceeds from ~~the sale of these bonds~~this issuance were used to reduce short-term debt and for general corporate purposes. On May 21, 2003 SCE&G issued $300 million First Mortgage Bonds having an annual interest rate of 5.30% and maturing on May 15, 2033. SCE&G used the net proceeds from the sale of these bonds and certain other SCE&G funds to redeem its $100 million principal amount of 7.625% First Mortgage Bonds due June 15, 2023, its $150 million principal amount of 7.50% First Mortgage Bonds due June 1, 2023 and its Junior Subordinated Debentures which effected the redemption of $50 million aggregate amount of 7.55% Trust Preferred Securities, Series A, issued by SCE&G Trust I. On November 6, 2003 SCE&G issued $250 million First Mortgage Bonds having an annual interest rate of 5.25% and maturing on November 1, 2018. SCE&G will use the net proceeds from the sale of these bonds for the payment at maturity of SCE&G's $100 million principal amount of 6.25% First Mortgage Bonds due December 15, 2003, for repayment of short-term debt primarily incurred as a result of SCE&G'ssupport GENCO's construction program and to repay intercompany advances borrowed for ~~general corporate purposes.~~ that purpose.

CAPITAL PROJECTS ~~In May 2002~~

Construction of SCE~~&G began construction of an~~&G's 875 megawatt generation facility in Jasper County, South Carolina ~~to supply electricity to its South Carolina customers.~~has been completed. The facility ~~will include~~includes three natural gas combustion-turbine generators and one steam-turbine generator. The $450 million facility ~~is expected to begin~~began commercial operation in ~~mid-2004, and SCG Pipeline, Inc., an affiliate, will transport natural gas to the facility. Costs incurred through September 30, 2003 totaled approximately $421 million.~~May 2004.

ENVIRONMENTAL MATTERS

For information on environmental matters see Note 5C ~~of Notes To Condensed Consolidated Financial Statements.~~ to condensed consolidated financial statements.

OTHER MATTERS

Nuclear Station ~~License Extension~~

Synthetic Fuel

Under a plan approved by the SCPSC, any tax credits generated and ultimately passed through to SCE&G from synfuel produced for and consumed by SCE&G, net of partnership losses and other expenses, have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions. See Note ~~1A of Notes~~1B to ~~Consolidated Financial Statements. On June 27, 2003~~condensed consolidated financial statements.

In March 2004 SCANA received a "No Change" letter from the Internal Revenue Service (IRS) announced that it is reviewing the scientific validity of certain test procedures and results that have been presented as evidence that solid coal-based synthetic fuels have undergone a significant chemical change. Pending completion of this review, the IRS suspended the issuance of Private Letter Rulings on the question of significant chemical change for requests that rely on the testing procedures and results being reviewed. Upon finishing this review, on October 29, 2003, the IRS issued Announcement 2003-70, finishing its review, and confirming that the test procedures and results used by taxpayers are scientifically valid if the procedures are applied in a consistent and unbiased manner.related to SCE~~&G believes its test procedures will meet the standards contemplated~~&G's interest in the ~~Announcement. Although one of~~synthetic fuel partnership S. C. Coaltech No. l L.P. for the ~~partnerships in which SCE&G owns an interest is currently under audit by~~tax year 2000. This letter supports SCANA's position that the ~~IRS, there have been no issues raised with respect to the validity of~~ synthetic fuel tax ~~credits. While SCE&G is not able to determine what conclusion the IRS will reach in these matters, to the extent the IRS disallows synfuel tax~~ credits generated by either of the two partnerships, the Company's and SCE&G's financial position, results of operations and cash flows would not be materially adversely affected. RESULTS OF OPERATIONS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2003 AS COMPARED TO THE CORRESPONDING PERIODS IN 2002
Net Income Net income for the third quarter and year to date periods ended September 30, 2003 and 2002 was as follows: - -------------------------------------------------------------- ------------------------------------------ Third Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change - ----------------------------- ---------- --------------------- ---------- ---------- -------------------- --------- ---------- ---------- ---------- Net income $87.8 $86.2 $1.6 1.9% $174.8 $177.5 $(2.7) (1.5%) - ----------------------------- ---------- ---------- ---------- ---------- ---------- ---------- ---------
Third Quarter 2003 vs 2002 Net income increased slightly due to higher electric margins of $6.3 million, reduced income tax expense due primarily to favorable income tax adjustments related to prior periods of $4.6 million and reduction of preferred dividend requirements of $0.9, which were partially offset by higher operation and maintenance expense of $4.0 million, higher depreciation expense of $4.8 million and higher property taxes of $2.6 million. Year to Date 2003 vs 2002 Net income decreased primarily due to higher operation and maintenance expense of $26.2 million, higher depreciation expense of $15.7 million, higher interest expense of $9.9 million, higher property taxes of $8.9 million and lower equity AFC of $2.9 million, which were partially offset by higher electric margins of $48.2 million, higher gas margins of $5.5 million and reduced income tax expense due primarily to favorable income tax adjustments related to prior periods of $4.6 million. ~~Pension Income Pension income during the three and nine months ended September 30, 2003 was recorded on SCE&G's financial statements as follows:~~
- ---------------------------------------------------------------------------- ------------------- ------------------- Third Quarter Year to Date Millions of dollars 2003 2002 2003 2002 - ---------------------------------------------------------------------------- --------- --------- --------- --------- - ---------------------------------------------------------------------------- --------- --------- --------- --------- Income Statement Impact: (Component of) reduction in employee benefit costs $0.7 $1.3 $(0.7) $7.8 Other income 2.2 4.4 6.1 8.4 Balance Sheet Impact: (Component of) reduction in capital expenditures 0.2 0.4 (0.2) 2.3 Component of (reduction in) amount due to Summer Station co-owner 0.1 0.1 (0.1) 0.7 - ---------------------------------------------------------------------------- --------- --------- --------- --------- - ---------------------------------------------------------------------------- --------- --------- --------- --------- Total Pension Income $3.2 $6.2 $5.1 $19.2 ============================================================================ ========= ========= ========= =========
For the last several years, the market value of SCE&G's retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. Pension income in all periods of 2003 decreased significantly compared to corresponding periods in 2002 primarily as a result of a less 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. SCE&G 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 nine months ended September 30, 2003 is primarily the result of the completion of the Urquhart Station repowering project in June 2002. In addition, in January 2003 the SCPSC issued an order allowing SCE&G to include all Jasper County Generating project expenditures as of December 31, 2002 and other construction work in progress expenditures as of June 30, 2002 in electric rate base. At the time the expenditures were included in rate base, AFC was no longer calculated on those amounts. These decreases were partially offset by increased AFC from subsequent construction expenditures related to the Jasper County Generating Station project in 2003 and the Lake Murray Dam project (see discussion at CAPITAL PROJECTS). Dividends Declared SCE&G's Board of Directors has declared the following dividends on common stock held by SCANA during 2003:
--------------------------- ----------------------------- ---------------------------- ----------------------- Declaration Date Amount Quarter Ended Payment Date --------------------------- ----------------------------- ---------------------------- ----------------------- February 20, 2003 $35.3 million March 31, 2003 April 1, 2003 May 1, 2003 $36.5 million June 30, 2003 July 1, 2003 July 31, 2003 $37.0 million September 30, 2003 October 1, 2003 --------------------------- ----------------------------- ---------------------------- -----------------------
~~Electric Operations Electric Operations is comprised of the electric portion of SCE&G and South Carolina Fuel Company, Inc. Changes in the electric operations sales margins were as follows:~~
---------------------------------- -------------------------------------- ----------------------------------------- Third Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change ---------------------------------- --------- --------- ------------------ ---------- ---------- ------------------- ---------------------------------- --------- --------- -------- --------- ---------- ---------- --------- --------- Operating Revenues $429.8 $425.4 $4.4 1.0% $1,125.0 $1,079.3 $45.7 4.2% Less: Fuel used in generation 78.0 85.9 (7.9) (9.2%) 217.9 216.6 1.3 0.6% Purchased power 41.7 35.7 6.0 16.8% 107.0 110.8 (3.8) (3.4%) ---------------------------------- --------- --------- -------- --------- ---------- ---------- --------- --------- ---------------------------------- --------- --------- -------- --------- ---------- ---------- --------- --------- Margin $310.1 $303.8 $6.3 2.1% $800.1 $751.9 $48.2 6.4% ================================== ========= ========= ======== ========= ========== ========== ========= =========
Third Quarter 2003 vs 2002 Margin increased primarily due to the increase in retail electric base rates approved in January 2003 of $24.5 million partially offset by less favorable weather of $18.5 million. Fuel used in generation decreased and purchased power increased due to planned plant outages. Year to Date 2003 vs 2002 Margin increased primarily due to the increase in retail electric base rates approved in January 2003 of $58.6 million and by $10.4 million due to customer growth and increased consumption. These increases were partially offset by $20.8 million due to the effects of less favorable weather. Fuel used in generation increased and purchased power decreased primarily due to a planned outage at GENCO in the second quarter of 2003. Gas Distribution Gas Distribution is comprised of the local distribution operations of SCE&G. Changes in the gas distribution sales margins were as follows:
---------------------------------- --------------------------------------- ---------------------------------------- Third Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change ---------------------------------- --------- --------- ------------------- --------- ---------- ------------------- ---------------------------------- --------- --------- --------- --------- --------- ---------- -------- ---------- Operating Revenues $54.6 $47.1 $7.5 15.9% $258.6 $207.2 $51.4 24.8% Less: Gas purchased for resale 43.8 36.0 7.8 21.7% 194.1 148.2 45.9 31.0% ---------------------------------- --------- --------- --------- -------- --------- ---------- Margin $10.8 $11.1 $(0.3) (2.7%) $64.5 $59.0 $5.5 9.3% ================================== ========= ========= ========= ========= ========= ========== ======== ==========
Third Quarter 2003 vs 2002 Margin decreased primarily due to an unfavorable competitive position of natural gas relative to alternate fuels of $1.3 million, partially offset by customer growth and increased consumption of $1.1 million. Year to Date 2003 vs 2002 Margin increased primarily due to customer growth of 1.3% and recovery of environmental remediation expenses of $1.7 million (offset in operations and maintenance), partially offset by increased competition with alternate fuels of $2.7 million.
Other Operating Expenses Changes in other operating expenses were as follows: ------------------------------------- -------------------------------------- ----------------------------------------- Third Quarter Year to Date Millions of dollars 2003 2002 Change 2003 2002 Change ------------------------------------- ---------- --------- ----------------- --------- ---------- -------------------- Other operation and maintenance $93.7 $89.7 $4.0 4.5% $295.4 $269.2 $26.2 9.7% Depreciation and amortization 47.4 42.6 4.8 11.3% 142.3 126.6 15.7 12.4% Other taxes 29.9 27.3 2.6 9.5% 90.5 81.6 8.9 10.9% ------------------------------------- ---------- --------- ------- --------- ---------- --------- ------------------------------------- ---------- --------- ------- --------- ---------- --------- Total $171.0 $159.6 $11.4 7.1% $528.2 $477.4 $50.8 10.6% ===================================== ========== ========= ======= ========= ========= ========== ========= ==========
Third Quarter 2003 vs 2002 Other operation and maintenance expenses increased primarily due to reduced pension income of $0.6 million and increased labor and benefit costs of $3.5 million. Depreciation and amortization expense increased primarily due to normal net property changes. Other taxes increased primarily due to increased property taxes. Year to Date 2003 vs 2002 Other operation and maintenance expenses increased primarily due to reduced pension income of $8.6 million, increased labor and benefits costs of $11.7 million, increased environmental remediation costs of $1.7 million and increased other operating expenses for electric generation and transmission of $1.0 million. Depreciation and amortization expense increased primarily due to normal net property additions of $9.4 million and the completion of the Urquhart Station repowering project in June 2002 of $4.2 million. Other taxes increased primarily due to increased property taxes. Other Income Other income, including AFC, for the year to date 2003 vs 2002 period decreased primarily due to completion of the Urquhart Station Repowering project in June 2002. In addition, in January 2003 the SCPSC issued an order allowing SCE&G to include all Jasper County Generating Project expenditures as of December 31, 2002 and other construction work in progress expenditures as of June 30, 2002 in electric rate base. At the time the expenditures were included in rate base, AFC was no longer calculated on those amounts. These decreases were partially offset by increased AFC from subsequent Jasper County Generation Station project expenditures and the Lake Murray Dam Project. Interest Expense Third Quarter 2003 vs 2002 Interest expense increased by $4.9 million due to increased long-term debt partially offset by $3.0 million due to lower interest rates. Year to Date 2003 vs 2002 Interest expense increased by $15.8 million due to increased long-term debt and by $2.9 million due to lower AFC. These increases were partially offset by $7.9 million due to lower interest rates. Income Taxes Income taxes for both the third quarter and year to date 2003 vs 2002 decreased primarily as a result of changes in operating income and favorable income tax adjustments related to prior periods. been properly claimed.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

All financial instruments held by SCE&G and GENCO described below are held for purposes other than trading.

Interest rate ~~risk -~~ risk—The table below provides information about long-term debt issued by SCE&G and GENCO 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.
As of September 30, 2003 Millions of dollars Expected Maturity Date There- Fair Liabilities 2003 2004 2005 2006 2007 after Total Value - ------------------------------ --------- -------- -------- -------- --------- ------------- ---------- -------------- - ------------------------------ --------- -------- -------- -------- --------- ------------- ---------- -------------- Long-Term Debt: Fixed Rate ($) 138.4 138.4 188.4 169.1 38.2 1,430.6 2,103.1 2,078.6 Average Interest Rate (%) 6.39 7.44 7.35 8.49 6.74 6.22 6.60

As of March 31, 2004	Expected Maturity Date
Millions of dollars Liabilities	2004	2005	2006	2007	2008	There- after	Total	Fair Value
Long-Term Debt:
Fixed Rate ($)	139.2	189.2	169.9	39.2	39.2	1,821.9	2,398.6	2,339.8
Average Interest Rate (%)	7.46	7.37	8.51	6.86	6.86	6.03	6.42

While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur. In June 2002 SCE&G entered into a parts availability agreement with a supplier whereby turbine and stator bar parts will be stored by SCE&G to be available when needed. The parts will remain the property of the supplier until such time as they are removed from storage by SCE&G and payment is made. SCE&G bears the risk of loss or repair for any part damaged while in storage and will pay an availability fee each quarter based on the daily available parts stored. In addition, SCE&G is obligated to purchase all remaining stored parts at the termination dates of the contract, June 2009 for the turbine parts and December 2006 for the stator bar parts. As such, SCE&G has recorded a liability in Other Long-Term Debt with an offsetting asset in Deferred Debits. At September 30, 2003 SCE&G had recorded $30.8 million for the turbine parts and $3.2 million for the stator bar parts.

Item 4. Controls and Procedures

As of ~~September 30, 2003~~March 31, 2004 an evaluation was performed under the supervision and with the participation of SCE&G's management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of SCE&G's disclosure controls and procedures. Based on that evaluation, SCE&G's management, including the CEO and CFO, concluded that as of ~~September 30, 2003~~March 31, 2004 SCE&G's disclosure controls and procedures were effective. There has been no change in SCE&G's internal control over financial reporting during the quarter ended ~~September 30, 2003~~March 31, 2004 that has materially affected or is reasonably likely to materially affect SCE&G's internal control over financial reporting.

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).
PART I. FINANCIAL INFORMATION Item 1. Financial Statements. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - -------------------------------------------------------- ---------------- ------------------- September 30, December 31, Millions of dollars 2003 2002 - -------------------------------------------------------- ---------------- ------------------- Assets Gas Utility Plant $932 $895 Accumulated depreciation (344) (318) Acquisition adjustment, net of accumulated amortization 210 210 - -------------------------------------------------------- ---------------- ------------------- Gas Utility Plant, Net 798 787 - -------------------------------------------------------- ---------------- ------------------- Nonutility Property and Investments, Net 27 28 - -------------------------------------------------------- ---------------- ------------------- Current Assets: Cash and temporary investments 5 1 Restricted cash and temporary investments 7 7 Receivables, net of allowance for uncollectible accounts of $1 and $2 38 98 Receivables-affiliated companies 13 14 Inventories (at average cost): Stored gas 62 38 Materials and supplies 5 6 Prepayments 8 1 Deferred income taxes, net 3 3 - -------------------------------------------------------- ---------------- ------------------- Total Current Assets 141 168 - -------------------------------------------------------- ---------------- ------------------- Deferred Debits: Due from affiliate-pension asset 14 14 Regulatory assets 30 20 Other 5 7 - -------------------------------------------------------- ---------------- ------------------- Total Deferred Debits 49 41 - -------------------------------------------------------- ---------------- ------------------- Total $1,015 $1,024 ======================================================== ================ =================== ======================================================== ================ =================== Capitalization and Liabilities Capitalization: Common equity $493 $487 Long-term debt, net 283 286 - -------------------------------------------------------- ---------------- ------------------- Total Capitalization 776 773 - -------------------------------------------------------- ---------------- ------------------- Current Liabilities: Short-term borrowings 35 31 Current portion of long-term debt 8 8 Accounts payable 27 44 Accounts payable-affiliated companies 4 7 Customer prepayments and deposits 10 12 Taxes accrued 5 5 Interest accrued 4 6 Distributions/dividends declared 4 5 Other 10 11 - -------------------------------------------------------- ---------------- ------------------- Total Current Liabilities 107 129 - -------------------------------------------------------- ---------------- ------------------- Deferred Credits: Deferred income taxes, net 96 91 Deferred investment tax credits 2 2 Due to affiliate-postretirement benefits 17 16 Regulatory liabilities 6 1 Other 11 12 - -------------------------------------------------------- ---------------- ------------------- Total Deferred Credits 132 122 - -------------------------------------------------------- ---------------- ------------------- Total $1,015 $1,024 ======================================================== ================ =================== See Notes to Condensed Consolidated Financial Statements. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - --------------------------------------------------------------------------------------- -------------------------- Three Months Ended Nine Months Ended September 30, September 30, Millions of dollars 2003 2002 2003 2002 - --------------------------------------------------------------------------- ----------- ------------ ------------- Operating Revenues $59 $39 $344 $222 Cost of Gas 37 18 221 107 - --------------------------------------------------------------------------- ----------- ------------ ------------- Gross Margin 22 21 123 115 - --------------------------------------------------------------------------- ----------- ------------ ------------- Operating Expenses: Operation and maintenance 19 16 57 50 Depreciation 9 9 26 26 Other taxes 2 2 5 5 - --------------------------------------------------------------------------- ----------- ------------ ------------- Total Operating Expenses 30 27 88 81 - --------------------------------------------------------------------------- ----------- ------------ ------------- Operating Income (Loss) (8) (6) 35 34 Other Income, Including Allowance for Equity Funds Used During Construction 2 1 6 3 Interest Charges, Net of Allowance for Borrowed Funds Used During Construction 5 5 16 17 - --------------------------------------------------------------------------- ----------- ------------ ------------- Income (Loss) Before Income Tax Expense (Benefit) and Cumulative Effect of Accounting Change (11) (10) 25 20 Income Tax Expense (Benefit) (4) (4) 9 7 - --------------------------------------------------------------------------- ----------- ------------ ------------- - --------------------------------------------------------------------------- ----------- ------------ ------------- Income (Loss) Before Cumulative Effect of Accounting Change (7) (6) 16 13 Cumulative Effect of Accounting Change, net of taxes - - - (230) - --------------------------------------------------------------------------- ----------- ------------ ------------- - --------------------------------------------------------------------------- ----------- ------------ ------------- Net Income (Loss) $(7) $(6) $16 $(217) =========================================================================== =========== ============ ============= See Notes to Condensed Consolidated Financial Statements. PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - ------------------------------------------------------------------------------------------ Nine Months Ended September 30, Millions of dollars 2003 2002 - ---------------------------------------------------------------------------- ------------- Cash Flows From Operating Activities: Net income (loss) $16 $(217) Adjustments to reconcile net income to net cash provided from operating activities: Cumulative effect of accounting change, net of taxes - 230 Depreciation 28 28 Allowance for funds used during construction (1) (1) Over (under) collection, gas cost adjustment clause (5) (26) Changes in certain assets and liabilities: (Increase) decrease in receivables, net 61 43 (Increase) decrease in inventories (23) 4 (Increase) decrease in regulatory assets - 1 Increase (decrease) in accounts payable and advances (20) (29) Increase (decrease) in deferred income taxes, net 5 (2) Increase (decrease) in taxes accrued - (1) Changes in other assets (5) (1) Changes in other liabilities 4 - - ---------------------------------------------------------------------------- ------------- Net Cash Provided From Operating Activities 60 29 - ---------------------------------------------------------------------------- ------------- Cash Flows From Investing Activities: Construction expenditures (36) (34) Nonutility and other (1) (1) - ------------------------------------------------------------------------- ------------- Net Cash Used For Investing Activities (37) (35) - ------------------------------------------------------------------------- ------------- Cash Flows From Financing Activities: Repayment of short-term borrowings, net (4) - Capital contributions from parent 3 1 Retirement of long-term debt (3) - Distributions/dividend payments (15) (9) - ------------------------------------------------------------------------- ------------- Net Cash Used For Financing Activities (19) (8) - ------------------------------------------------------------------------- ------------- Net Increase (Decrease) In Cash and Temporary Investments 4 (14) Cash and Temporary Investments, January 1 1 18 - ------------------------------------------------------------------------- ------------- Cash and Temporary Investments, September 30 $5 $4 ========================================================================= ============= Supplemental Cash Flow Information: Cash paid for - Interest (net of capitalized interest of $0.8 and $0.7) $16 $16 - Income taxes 14 13 See Notes to Condensed Consolidated Financial Statements.

Item 1. Financial Statements

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

Millions of dollars			March 31, 2004			December 31, 2003
Assets
Gas Utility Plant			$	931		$	923
Accumulated depreciation				(261	)		(256	)
Acquisition Adjustment, Net of Accumulated Amortization				210			210

Gas Utility Plant, Net				880			877

Nonutility Property and Investments, Net				27			28

Current Assets:
	Cash and temporary investments			33			18
	Restricted cash and temporary investments			8			7
	Receivables, net of allowance for uncollectible accounts of $3 and $3			96			115
	Receivables-affiliated companies			6			5
	Inventories (at average cost):
		Stored gas		26			56
		Materials and supplies		5			5
	Prepayments			1			2
	Deferred income taxes, net			4			3

	Total Current Assets			179			211

Deferred Debits:
	Due from affiliate-pension asset			13			13
	Regulatory assets			19			17
	Other			8			6

	Total Deferred Debits			40			36

Total			$	1,126		$	1,152

Capitalization and Liabilities
Capitalization:
	Common equity		$	521		$	502
	Long-term debt, net			278			278

	Total Capitalization			799			780

Current Liabilities:
	Short-term borrowings			—			55
	Current portion of long-term debt			8			8
	Accounts payable			35			48
	Accounts payable-affiliated companies			5			2
	Customer deposits			7			7
	Taxes accrued			25			10
	Interest accrued			4			6
	Distributions/dividends declared			4			4
	Other			12			15

	Total Current Liabilities			100			155

Deferred Credits:
	Deferred income taxes, net			96			96
	Deferred investment tax credits			2			2
	Due to affiliate-postretirement benefits			17			17
	Regulatory liabilities			99			86
	Other			13			16

	Total Deferred Credits			227			217

Total			$	1,126		$	1,152

See Notes to Condensed Consolidated Financial Statements.

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

		Three Months Ended March 31,
Millions of dollars		Three Months Ended March 31,
Millions of dollars		2004		2003
Operating Revenues		$	226	$	203
Cost of Gas			153		131

Gross Margin			73		72

Operating Expenses:
	Operation and maintenance		20		19
	Depreciation		9		9
	Other taxes		2		2

	Total Operating Expenses		31		30

Operating Income			42		42
Other Income, Including Allowance for Equity Funds Used During Construction			—		2
Interest Charges, Net of Allowance for Borrowed Funds Used During Construction			5		5

Income Before Income Tax Expense			37		39
Income Tax Expense			14		15

Net Income		$	23	$	24

See Notes to Condensed Consolidated Financial Statements.

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

				Three Months Ended March 31,
Millions of dollars				Three Months Ended March 31,
Millions of dollars				2004			2003
Cash Flows From Operating Activities:
	Net income			$	23		$	24
	Adjustments to reconcile net income to net cash provided from operating activities:
		Depreciation and amortization			9			9
		Loss on sale of assets			1			—
		Over (under) collection, gas cost adjustment clause			7			(6	)
		Changes in certain assets and liabilities:
			(Increase) decrease in receivables, net		18			(6	)
			(Increase) decrease in inventories		30			20
			Increase (decrease) in accounts payable		(10	)		1
			Increase (decrease) in deferred income taxes, net		(1	)		1
			Increase (decrease) in regulatory liabilities		1			—
			Increase (decrease) in taxes accrued		15			15
		Changes in other assets			—			2
		Changes in other liabilities			(6	)		(8	)

Net Cash Provided From Operating Activities					87			52

Cash Flows From Investing Activities:
	Construction expenditures				(13	)		(10	)
	Nonutility and other				—			(1	)

Net Cash Used For Investing Activities					(13	)		(11	)

Cash Flows From Financing Activities:
	Repayment of short-term borrowings, net				(55	)		(31	)
	Distributions/dividend payments				(4	)		(5	)

Net Cash Used For Financing Activities					(59	)		(36	)

Net Increase In Cash and Temporary Investments					15			5
Cash and Temporary Investments, January 1					18			1

Cash and Temporary Investments, March 31				$	33		$	6

Supplemental Cash Flow Information:
Cash paid for—Interest (net of capitalized interest of $0.2 and $0.4)				$	7		$	6
—Income taxes					—			—

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ~~September 30, 2003~~
March 31, 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 (the Company) Annual Report on Form 10-K for the year ended December 31, ~~2002.~~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~~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, 2003~~March 31, 2004 approximately ~~$30~~$19 million and $6$99 million of regulatory assets and liabilities, respectively, as shown below. September 30, December 31, Millions of dollars 2003 2002 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Excess deferred income taxes $- $(1) Under-collections-gas cost adjustment clause, net 15 11 Deferred environmental remediation costs 9 9 - -------------------------------------------------------------------------------- Total $24 $19 ================================================================================respectively. Information relating to regulatory assets and liabilities follows.

Millions of dollars	March 31, 2004			December 31, 2003
Excess deferred income taxes	$	(2	)		—
Over-collections-gas cost adjustment clause, net		(8	)	$	(1	)
Deferred environmental remediation costs		9			9
Non-legal asset retirement obligations		(79	)		(77	)

Total	$	(80	)	$	(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-collections-gas~~

Over-collections-gas cost adjustment clause, net represents amounts ~~under-collected~~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 $2.4 million in costs have been incurred and deferred for subsequent rate consideration. (See Note 4.) Management believes that all MGP cleanup costs will be recoverable through gas rates. ~~A portion~~

Non-legal asset retirement obligations represent net collections through depreciation rates of estimated costs to be incurred for the ~~costs incurred are being recovered through rates, and management believes the remaining costs~~future retirement of ~~approximately $7.5 million will be recoverable. Amounts incurred and deferred to date that are not currently being recovered through gas rates are approximately $1.5 million. (See Note 5.)~~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.

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. New Accounting Standards The Company adopted SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002. In connection with this implementation, the Company performed a valuation analysis of its acquisition adjustment using an independent appraisal. The analysis indicated that the carrying amount of the acquisition adjustment exceeded its fair value by approximately $230 million. The resulting impairment charge is reflected on the Condensed Consolidated Statement of Operations as the cumulative effect of an accounting change. SFAS 142 requires that an impairment evaluation be performed annually and at the same time each year. The Company performed its annual evaluation as of January 1, 2003 and no further impairment was indicated. The Company adopted SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. SFAS 143 applies to legal obligations associated with the retirement of tangible long-lived assets (ARO) and requires the Company to recognize, as a liability, the fair value of an ARO in the period in which it is incurred and to accrete the liability to its present value in future periods. The Company believes that any ARO related to the Company's property would be insignificant and, due to the indeterminate life of the related assets, an ARO could not be reasonably estimated. The Company adopted SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," effective January 1, 2003. The provisions of SFAS 145, among other things, discontinue treatment of gains or losses from the early extinguishment of debt as extraordinary items unless such early extinguishment meets the criteria of Accounting Principles Board Opinion (APB) 30. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 145. The Company adopted SFAS 146 "Accounting for Costs Associated with Exit or Disposal Activities," effective January 1, 2003. This statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 146. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" was issued in April 2003. SFAS 149 amends and clarifies accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 149. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" was issued in May 2003. SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). SFAS 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 150. C. Total Comprehensive Income

Total comprehensive income ~~(loss)~~ was not significantly different from net income ~~(loss)~~ for any period reported. Accumulated other comprehensive income (loss) of the Company totaled $(1.1) million and ~~$(1.3)~~$(1.0) million as of ~~September 30, 2003~~March 31, 2004 and December 31, ~~2002,~~2003, respectively. D.

C. Reclassifications

Certain amounts from prior periods have been reclassified to conform with the presentation adopted for ~~2003.~~ 2004.

2. ACCOUNTING CHANGE As a result of the January 1, 2002 adoption of SFAS 142, the Company recorded a $230 million impairment charge related to the acquisition adjustment which had been recorded in connection with its acquisition by SCANA Corporation. The charge is reflected on the Condensed Consolidated Statements of Operations as the cumulative effect of an accounting change. See additional information at Note 1B. 3. 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, ~~2002~~2003 through ~~September 30, 2003~~March 31, 2004 was as follows: ~~Rate Per Therm Effective Date Rate Per Therm Effective Date $.460 January-February 2003 $.300 January 2002 $.595~~

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

For service rendered on and after March 2003 $.215 February-June 2002 $.725 April-September 2003 $.350 July-October 2002 $.410 November-December 2002 On October 13, 2003 in connection with the Company's 2003 Annual Prudence Review,1, 2004, the NCUC ~~determined that~~authorized the ~~Company's gas costs, including all hedging transactions, were reasonable~~Company to implement decrements in its sales and ~~prudently incurred during the 12-month review period ended March 31, 2003. The NCUC also authorized new~~transportation rate ~~decrements~~schedules to ~~refund overcollections~~reflect a decrease of ~~certain gas costs included~~approximately $5.7 million in the Company's ~~deferred accounts, effective November 1, 2003.~~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 Company estimates that the cost of this project will be approximately ~~$31.4~~$31 million. The Madison County and Jackson County portions of the project were completed in 2002, and the Swain County portion ~~is expected to be~~was completed and placed in ~~the spring of~~service in April 2004. Through ~~September 30, 2003~~March 31, 2004 approximately ~~$24.4~~$29 million had been spent on this project.

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 cases until

August 2005. General rate relief can be obtained during this period to recover costs associated with material adverse governmental actions and force majeure events. 4.

3. FINANCIAL INSTRUMENTS

The Company follows the guidance required by SFAS 133 "Accounting for Derivative Instruments and Hedging Activities," as amended, ~~requires the~~in accounting for derivatives, including those arising from cash flow hedges related to natural gas.

The Company to recognize all derivative instruments as either assets or liabilities in the statement of financial position and to measure those instruments at fair value. SFAS 133 further provides that changes in the fair value of derivative instruments are either recognized in earnings or reported as a component of other comprehensive income, depending upon the intended use of the derivative and the resulting designation. The fair value of the derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or quotations from independent parties. In January 2003 the Company filed a summary of itsutilizes hedging ~~program~~activities for natural gas purchases with the NCUC for informational purposes. The primary goal of the program is to reduce price volatility to firm customers. In an October 2003 order, the NCUC declared the program was reasonable.purchases. Transaction fees and any realized gains or losses are recorded in deferred accounts for subsequent rate consideration. As of ~~September 30, 2003~~March 31, 2004 the Company had deferred a net ~~gain~~costs of approximately ~~$0.6~~$1.9 million.

The Company ~~uses interest rate~~also utilizes swap agreements to manage interest rate risk. These swap agreements provide for the Company to pay variable rate and receive fixed rate interest payments and are designated as fair value hedges of certain debt instruments. The Company may terminate a swap agreement and may replace it with a new swap also designated as a fair value hedge. The fair value of interest rate swaps is recorded within other deferred debits on the balance sheet. The resulting credits serve to reflect the hedged long-term debt at its fair value. Periodic receipts or payments related to the interest rate swaps are credited or charged to interest expense as incurred. At ~~September 30, 2003~~March 31, 2004 the estimated fair value of the Company's swaps totaled ~~$2.9~~$2.7 million related to combined notional amounts of ~~$37.4~~$33.1 million. 5.

4. 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 ~~$7.5~~approximately $6.8 million, which reflects the estimated remaining liability at ~~September 30, 2003.~~March 31, 2004. Amounts incurred and deferred to date that are not currently being recovered through gas rates are approximately ~~$1.5~~$2.4 million. Management believes that all MGP cleanup costs will be recoverable through gas rates. 6.

5. SEGMENT OF BUSINESS INFORMATION

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

Disclosure of Reportable Segments ~~(Millions~~
(Millions of dollars) Three Months Ended September 30, 2003 2002 -------------------------------------------------- --------------------------- -------------------------------------------------- ------------- ------------- External Operating External Operating Revenue Loss Revenue Loss -------------------------------------------------- ------------- ------------- Gas Distribution $59 $(8) $39 $(6) All Other - n/a - n/a -------------------------------------------------- ------------- ------------- Consolidated Total $59 $(8) $39 $(6) ================================================== ============= =============
Nine Months Ended September 30, 2003 2002 ----------------------------------------------------------- ------------- -------------- ------------- ----------------------------------------------------------- ------------- -------------- ------------- External Operating Segment External Operating Segment Revenue Income Assets Revenue Income Assets ----------------------------------------------------------- ------------- -------------- ------------- Gas Distribution $344 $35 $997 $222 $34 $1,155 All Other - n/a 28 - n/a 29 Adjustments/Eliminations - - (10) - - 2 ----------------------------------------------------------- ------------- -------------- ------------- Consolidated Total $344 $35 $1,015 $222 $34 $1,186 =========================================================== ============= ============== =============

	2004						2003
Three months Ended March 31,	2004						2003
Three months Ended March 31,	External Revenue		Operating Income		Segment Assets		External Revenue		Operating Income		Segment Assets
Gas Distribution	$	226	$	42	$	1,039	$	203	$	42	$	1,023
All Other		—		n/a		28		—		n/a		28
Adjustments/Eliminations		—		—		59		—		—		(18	)

Consolidated Total	$	226	$	42	$	1,126	$	203	$	42	$	1,033

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

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

The following discussion should be read in conjunction with Management's Narrative Analysis of Results of Operations appearing in Public Service Company of North Carolina, Incorporated's (PSNC Energy) Annual Report on Form 10-K for the year ended December 31, ~~2002.~~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) changes in the utility regulatory environment, (3) changes in the economy, especially in PSNC Energy's service territory, (4) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (5) growth opportunities, (6) the results of financing efforts, (7) changes in PSNC Energy's accounting policies, (8) weather conditions, especially in areas served by PSNC Energy, (9) performance of SCANA Corporation's (SCANA) pension plan assets and the impact on PSNC Energy's results of operations, (10) inflation, (11) changes in environmental regulations and (12) 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 ~~(Loss)~~ and Distributions/Dividends

Net income ~~(loss)~~decreased for the ~~nine~~three months ended ~~September 30,~~March 31, 2004 approximately $1.6 million compared to the same period in 2003 and 2002 was as follows: - ------------------------------------------------------------------------------- Nine Months Ended September 30, Millions of dollars 2003 2002 - ------------------------------------------------------------------ ------------ Net income (loss) $15.9 $(216.5) Less: Cumulative effect of accounting change - (229.6) - ------------------------------------------------------------------ ------------ - ------------------------------------------------------------------ ------------ Income before cumulative effect of accounting change $15.9 $13.1 ================================================================== ============ Income before cumulative effect of accounting change increased approximately $2.8 million primarily due to ~~increased margin of $8.1 million and other income of $3.2 million which were partially offset by~~ higher operating expenses of ~~$6.4~~$1.7 million and ~~higher~~lower other income of $1.5 million, partially offset by increased margin of $0.7 million and lower income taxes of ~~$2.2~~$0.9 million. In connection with the implementation of SFAS 142, PSNC Energy performed a valuation analysis of its acquisition adjustment using an independent appraisal. The analysis indicated that the carrying amount of the acquisition adjustment exceeded its fair value by $230 million. As a result, PSNC Energy recorded an impairment charge of $230 million effective January 1, 2002. The charge is presented on the Condensed Consolidated Statements of Operations as the Cumulative Effect of an Accounting Change. SFAS 142 requires that an impairment evaluation be performed annually and at the same time each year. PSNC Energy performed an annual evaluation as of January 1, 2003 and no further impairment was indicated.

The nature of PSNC Energy's business is seasonal. The quarters ending ~~June 30~~March 31 and ~~September 30~~December 31 are generally PSNC Energy's ~~least~~most profitable quarters due to ~~decreased~~increased 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 2003: - --------------------- --------------- -------------------- ------------------- Declaration Date Amount Quarter Ended Payment Date - --------------------- --------------- -------------------- ------------------- - --------------------- --------------- -------------------- ------------------- February 20, 2003 $4.5 million March 31, 2003 April 1, 2003 May 1, 2003 $4.5 million June 30, 2003 July 1, 2003 July 31, 2003 $4.0 million September 30, 2003 October 1, 2003 - --------------------- --------------- -------------------- ------------------- 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

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 2003 2002 Change ------------------------ --------- --------- --------------------- ------------------------ ---------- Operating revenues $344.0 $222.0 $122.0 55.0% Less: Cost of gas 220.6 106.7 113.9 106.8% ------------------------ --------- --------- ---------- Gross margin $123.4 $115.3 $8.1 7.0% ======================== ========= ========= ========== ==========

	First Quarter
Millions of dollars	2004		% Change		2003
Operating revenues	$	226.0	11.2	%	$	203.2
Less: Cost of gas		153.4	16.8	%		131.3

Gross margin	$	72.6	1.0	%	$	71.9

Gas distribution sales margin for the ~~nine~~three months ended ~~September 30, 2003~~March 31, 2004 increased primarily due to ~~weather that was 14% colder than in 2002 and increased~~ customer growth of approximately ~~2.7%. Revenues~~$1.9 million, higher other operating revenues of $0.3 million and a positive margin impact from changes in the benchmark cost of gas ~~increased as~~of approximately $0.3 million. This increase was partially offset by a ~~result~~decline in customer usage per degree day of ~~higher commodity natural gas prices.~~ approximately $2.1 million.

Operation and Maintenance Expenses

Operation and maintenance expenses increased ~~$6.4~~$1.7 million for the ~~nine~~three months ended ~~September 30, 2003~~March 31, 2004 compared to the same period in ~~2002~~2003 primarily due to increased ~~bad debt expense of $2.4 million related to greater natural gas throughput and increased cost of gas. Also contributing to the increase are higher~~ labor and benefits costs of ~~$1.6~~$0.9 million and increased ~~outside labor~~administrative and general business expenses of ~~$1.7 million and the impact of reduced pension income of~~ $0.7 million.

Other Income

Other income ~~increased $3.2~~decreased $1.5 million compared to the same period in ~~2002~~2003 primarily due to ~~increased income~~a $1.0 million loss recognized on the sale of $1.1 million from secondary market activities, such as off-system gas sales and pipeline capacity release, and increased 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. In addition, merchandising and jobbing income increased $1.4 million due to reduced interest income of $0.8 million~~Energy's former corporate headquarters in ~~2002 and a reduced provision for bad debt of $0.6 million.~~ Gastonia, North Carolina.

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 ~~2003~~2004 construction budget is approximately ~~$46.7~~$51 million, compared to actual construction expenditures ~~for 2002~~through March 31, 2004 of ~~$47.8~~$13.4 million. PSNC Energy's ratio of earnings to fixed charges for the 12 months ended ~~September 30, 2003~~March 31, 2004 was ~~2.96.~~3.27.

At ~~September 30, 2003~~March 31, 2004 PSNC Energy had ~~$35.4 million in~~no outstanding short-term borrowings and had unused lines of credit of ~~$89.6~~$125 million.

Item 4. Controls and Procedures

As of ~~September 30, 2003~~March 31, 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, 2003~~March 31, 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, 2003~~March 31, 2004 that has materially affected or is reasonably likely to materially affect PSNC Energy's internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings The following legal proceedings were pending at September 30, 2003. These proceedings affect SCANA Corporation and its subsidiaries (the Company) and, to the extent indicated, they also affect SCE&G or PSNC Energy. Rate and Other Regulatory Matters In May 2002 the SCPSC issued an order approving SCE&G's request to increase the fuel component of rates charged to electric customers from 1.579 cents per KWh to 1.722 cents per KWh. The increase reflected higher fuel costs projected for the period May 2002 through April 2003. The increase also provided continued recovery for under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of SCE&G's base load generating plants in winter 2000-2001. The new rates were effective as of the first billing cycle in May 2002. The Consumer Advocate of South Carolina appealed to the South Carolina Circuit Court (Circuit Court) the portion of the SCPSC's order related to the recovery of certain purchased power costs. The appeal is still pending. In April 2003 the SCPSC issued an order approving SCE&G's request to maintain the fuel cost component of rates at 1.678 cents per KWh, effective May 1, 2003. The SCPSC also reaffirmed the prudence of SCE&G's purchasing practices and recognized the efficiency of SCE&G's electric generating plants; however, it deferred action on the recovery of certain purchased power costs pending the appeal to the Circuit Court of the SCPSC's May 2002 order. On October 13, 2003 in connection with PSNC Energy's 2003 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, 2003. The NCUC also authorized new rate decrements to refund overcollections of certain gas costs included in PSNC Energy's deferred accounts, effective November 1, 2003. On October 28, 2003, as part of the annual review of gas costs, the SCPSC approved SCE&G's request to decrease the cost of gas component from $.928 per therm to $.867 per therm effective with the first billing cycle in November 2003. The SCPSC allows SCE&G to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former MGPs. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for SCE&G's gas operations that had previously been recorded in deferred debits. In October 2003, as a result of the annual review, the SCPSC approved SCE&G's request to reduce the billing surcharge from 3.0 cents per therm to 2.2 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2009, of the balance remaining at September 30, 2003 of $11.6 million Lake Murray Dam Reinforcement In October 1999 the United States Federal Energy Regulatory Commission (FERC) mandated that SCE&G reinforce its Lake Murray dam in order to comply with new federal safety standards and maintain the lake in case of an extreme earthquake. Construction for the project and related activities, which began in the third quarter of 2001 is expected to cost approximately $275 million and be completed in 2005. Costs incurred through September 30, 2003 totaled approximately $126 million. Environmental SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for benzene contamination in the intermediate aquifer on surrounding properties. SCE&G anticipates that the remaining remediation activities will be completed by the end of 2004, with certain monitoring and retreatment activities continuing until 2007. As of September 30, 2003, SCE&G has spent approximately $19.6 million to remediate the Calhoun Park site. Total remediation costs are estimated to be $21.9 million. SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by DHEC. SCE&G is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. In addition, in March 2003 SCE&G signed a consent agreement with DHEC related to a site formerly owned by SCE&G. The site contained residue material that was moved from an MGP site. The removal action for this site has been completed. SCE&G anticipates that major remediation activities for the three owned sites will be completed before 2006. As of September 30, 2003, SCE&G has spent approximately $3.9 million related to these three sites, and expects to spend an additional $5.2 million. Total remediation costs are estimated to be $9.1 million. 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 $7.5 million, which reflects the estimated remaining liability at September 30, 2003. Amounts incurred and deferred to date that are not currently being recovered through gas rates are approximately $1.5 million. Management believes that all MGP cleanup costs incurred by PSNC Energy will be recoverable through gas rates. Pending or Threatened Litigation In 1999 an unsuccessful bidder for the purchase of propane gas assets of a subsidiary of the Company filed suit against SCANA Corporation in South Carolina 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. The Company is confident in its position and intends to vigorously defend the lawsuit. The Company does not believe that the resolution of this issue will have a material adverse impact on its results of operations, cash flows or financial position. In 2001 a subsidiary of the Company entered into, in the ordinary course of business, a 15-year take-and-pay contract with an unaffiliated natural gas supplier to purchase 190,000 DT of natural gas per day beginning in the spring of 2004. In December 2002, as a result of the failure of the supplier and its guarantor to meet contractual obligations related to credit support provisions, the subsidiary terminated the contract and the supplier initiated arbitration. A hearing under the binding arbitration provisions of the contract was postponed from September 2003 until at least January 2004 after the parties made progress towards a settlement. In initial pleadings for the hearing, the supplier demanded payment of at least $134 million in damages from the subsidiary; conversely, the subsidiary demanded payment of no less than $154 million in damages from the supplier. The Company is confident of the propriety of its actions and will vigorously pursue its position if the arbitration hearing is held. 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. An action was filed on October 22, 2003 against SCE&G by the State of South Carolina. The Complaint alleges SCE&G violates the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality's limits. The Complaint also alleges that SCE&G failed to obey, observe, or comply with the lawful order of the SCPSC by charging franchise fees to those not residing in a municipality. The Complaint seeks restitution to all affected customers and penalties up to $5,000 for each separate violation. SCE&G is confident of the reasonableness of its actions and intends to mount a vigorous defense. The allegations contained in this Complaint are the subject of a similar lawsuit that was filed and served on SCE&G and a Motion to Dismiss is pending. The allegations are also the subject of a threatened class action lawsuit. SCE&G further believes that the resolution of this action will not have a material adverse impact on its results of operations, cash flows or financial condition. In addition, SCE&G filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to SCE&G's electric and gas service, to approve SCE&G's efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation which the SCPSC deems just and proper to regulate the franchise fee collection process. On August 21, 2003, SCE&G was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and South Carolina Electric & Gas Company, in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. The plaintiffs are seeking damages for the alleged improper use of electric transmission easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to non-utility third parties or telecommunication companies for other than the electric utilities' internal use along the electric transmission line right-of-way constitutes a trespass. The Company is confident of the propriety of its actions and intends to mount a vigorous defense. The Company further believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.

The Company, SCE&G and PSNC Energy are ~~also~~ engaged in various ~~other~~ claims and litigation incidental to their business operations which management anticipates will be resolved without material loss to the Company. The status of matters previously disclosed in the Company's Annual Report on Form 10-K for 2003 have not changed significantly.

Item 2,2. Purchases of Equity Securities by the Issuer and Affiliated Purchases

Period	(a) Total number of shares (or units) purchased	(b) Average price paid per share (or unit)		(c) Total number of shares (or units) purchased as part of publicly announced plans or programs	(d) Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs
January 1, 2004– January 31, 2004	—		—	—	1,155,670
February 1, 2004– February 29, 2004	55,000	$	34.54	55,000	1,100,673
March 1, 2004– March 31, 2004	60,400	$	35.86	60,400	1,018,981

Total	115,400	$	35.23	115,400	1,018,981

On October 24, 2003, the Company announced that it would repurchase shares of SCANA stock on the open market. Total shares repurchased could not exceed the aggregate, measured at the time of any such purchase, of the number of shares theretofore issued pursuant to the exercise of options granted under the Long-Term Equity Compensation Plan (the Plan) plus the number of shares issuable upon the exercise of options exercisable under the Plan as of the date of such purchase or to become exercisable within 60 days of such date. No expiration date was stated, and the program under which such repurchases were made did not expire during the period covered by the above table. Effective April 29, 2004, the Company discontinued purchasing outstanding shares of common stock on the open market.

Item 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 subsidiaries, 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.

B. Reports on Form 8-K during the ~~third~~first quarter ~~2003~~2004 were as follows: SCANA Corporation: Date of Report: July 25, 2003 Items reported: Items 7 and 9 (Item 12 disclosure) South Carolina Electric & Gas Company: Date of Report: July 25, 2003 Items reported: Items 7 and 9 (Item 12 disclosure) Public Service Company of North Carolina, Incorporated: Date of Report: July 25, 2003 Items reported: Items 7 and 9 (Item 12 disclosure)


SCANA Corporation:
Date of report:		February 13, 2004
Items reported:		Items 7 & 12
South Carolina Electric & Gas Company:
Date of report:		February 13, 2004
Items reported:		Items 7 & 12
Public Service Company of North Carolina, Incorporated:
Date of report:		February 13, 2004
Items reported:		Items 7 & 12

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 thereunto duly authorized. SCANA CORPORATION SOUTH CAROLINA ELECTRIC & GAS COMPANY PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED (Registrants) November 6, 2003 By: s/James E. Swan, IV -------------------------------------- James E. Swan, IV Controller (Principal accounting officer)

~~EXHIBIT INDEX Exhibit~~
		SCANA CORPORATION SOUTH CAROLINA ELECTRIC & GAS COMPANY PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED (Registrants)
May 5, 2004		By:	/s/ JAMES E. SWAN, IV James E. Swan, IV Controller (Principal accounting officer)

EXHIBIT INDEX

	Applicable to Form 10-Q of
Exhibit No.	SCANA	SCE&G	PSNC Energy	Description ~~Energy~~ ~~2.01~~
3.01	X X Agreement and Plan of Merger, dated as of February 16, 1999 as amended and restated as of May 10, 1999, by and among Public Service Company of North Carolina, Incorporated, SCANA Corporation, New Sub I, Inc. and New Sub II, Inc. (Filed as Exhibit 2.1 to Registration Statement No. 333-78227 on Form S-4) 3.01 X			Restated Articles of Incorporation of SCANA Corporation as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. ~~33-49145)~~ 33-49145 and incorporated by reference herein)
3.02	X			Articles of Amendment ~~of SCANA,~~ dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. ~~33-62421)~~ 33-62421 and incorporated by reference herein)
3.03		X		Restated Articles of Incorporation of ~~SCE&G,~~South Carolina Electric & Gas Company, as adopted on May 3, 2001 (Filed as Exhibit 3.01 to Registration Statement No. ~~333-65460)~~ 333-65460 and incorporated by reference herein)
3.04		X		Articles of Amendment ~~of the Articles of Incorporation of SCE&G dated~~effective as of the dates indicated below and filed as exhibits to the Registration Statements ~~or Exchange Act filings as~~ 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 3.05	to Registration No. 333-108760
				May 22, 2003	Exhibit 3.05	to Registration No. 333-108760
				June 18, 2003	Exhibit 3.06	to Registration No. 333-108760
				August 7, 2003	Exhibit 3.06	to Registration No. 333-108760
3.05	X			Articles of Correction ~~of the~~filed on June 1, 2001 correcting May 22, 2001 Articles of ~~Incorporation of SCE&G dated June 1, 2001~~Amendment (Filed as Exhibit 3.03 to Registration Statement No. ~~333-65460)~~ 333-65460 and incorporated by reference herein)
3.06		X		Articles of ~~Incorporation of PSNC Energy (formerly New Sub II, Inc.) dated~~Correction filed on February ~~12, 1999 (Filed as Exhibit 3.01 to Registration Statement No. 333-45206) 3.07 X~~17, 2004 correcting the Articles of Amendment ~~of PSNC Energy~~dated as ~~adopted on February 10, 2000 (Filed~~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 ~~3.02 to Registration Statement No. 333-45206)~~3.06
				May 22, 2001	Exhibit 3.07
				June 14, 2001	Exhibit 3.08 ~~X Articles of Correction of PSNC Energy dated February 11, 2000 (Filed as~~
				August 30, 2001	Exhibit ~~3.03 to Registration Statement No. 333-45206)~~ 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

3.07

By-Laws of SCANA as revised and amended on December 13, 2000 (Filed as Exhibit 3.01 to Registration Statement No. ~~333-68266) 3.10~~ 333-68266 and incorporated by reference herein)

3.08

By-Laws of SCE&G as ~~amended~~revised and ~~adopted~~amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. ~~333-65460)~~ ~~Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description Energy 3.11~~ 333-65460 and incorporated by reference herein)

3.09

By-Laws of PSNC Energy as revised and amended on February 22, 2001 (Filed as Exhibit 3.01 to Registration Statement No. ~~333-68516)~~ 333-68516 and incorporated by reference herein)

4.01

Articles of Exchange of South Carolina Electric ~~and~~& Gas Company and SCANA Corporation (Filed as Exhibit 4-A to Post-Effective Amendment No. 1 to Registration Statement No. ~~2-90438)~~ 2-90438 and incorporated by reference herein)

4.02

Indenture dated as of November 1, 1989 between SCANA Corporation and The Bank of New York, as Trustee (Filed as Exhibit 4-A to Registration ~~Statement~~ No. ~~33-32107)~~ 33-32107 and incorporated by reference herein)

4.03

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)~~ 2-26459 and incorporated by reference herein)

4.04

Fourth Supplemental Indenture dated as of April 1, 1950, to Indenture referred to in Exhibit 4.03, pursuant to which SCE&G assumed said Indenture ~~(Filed as Exhibit~~(Exhibit 2-C to Registration Statement No. ~~2-26459)~~ 2-26459 and incorporated by reference herein)

4.05

Fifth through Fifty-third Supplemental ~~Indentures to~~ Indenture referred to in Exhibit 4.03 dated as of the dates indicated below and filed as exhibits to the Registration Statements ~~whose file numbers are~~ set forth below 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 ~~Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description Energy~~

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 ~~June~~

March 1, ~~1981~~ 1982

Exhibit 4-D

to Registration No. 2-73321 ~~March 1,~~

April 15, 1982

Exhibit 4-D

to Registration No. 33-49421 ~~April 15,~~

May 1, 1982

Exhibit 4-D

to Registration No. 33-49421 ~~May~~

December 1, ~~1982~~ 1984

Exhibit 4-D

to Registration No. 33-49421

December 1, ~~1984~~ 1985

Exhibit 4-D

to Registration No. 33-49421 ~~December~~

June 1, ~~1985~~ 1986

Exhibit 4-D

to Registration No. 33-49421 ~~June~~

February 1, ~~1986~~ 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. ~~33-57955~~ 33-49421

May 1, 1999

Exhibit 4.04

to Registration No. 333-86387

4.06

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)~~ 33-49421 and incorporated by reference herein)

4.07

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)~~ 33-49421 and incorporated by reference herein)

4.08

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)~~ 33-57955 and incorporated by reference herein)

4.09

Indenture dated as of January 1, 1996 between PSNC ~~Energy~~ and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.08 to Registration Statement No. ~~333-45206)~~ 333-45206 and incorporated by reference herein)

4.10

First through Fourth Supplemental ~~Indentures~~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 ~~Exhibit Applicable to Form 10-Q of No. SCANA SCE&G~~

4.11

PSNC ~~Description Energy 4.11 X PSNC Energy~~ $150 million medium-term note issued February 16, ~~2002~~2001 (Filed as Exhibit 4.06 to Registration Statement No. ~~333-68516) *10.01~~ 333-68516 and incorporated by reference herein)

*10.01

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) *10.02~~ 2003 and incorporated by reference herein)

*10.02

SCANA Director Compensation and Deferral Plan as amended January 1, 2001 (Filed as Exhibit 4.03 to Registration Statement No. ~~333-18973) *10.03~~ 333-18973 and incorporated by reference herein)

*10.03

Amendment to SCANA ~~Supplemental~~Director Compensation and Deferral Plan adopted April 29, 2004 (Filed herewith)

*10.04

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) *10.04~~ 2001 and incorporated by reference herein)

*10.05

SCANA Key Executive Severance Benefits Plan as amended July 1, 2001 (Filed as Exhibit 10.03 to Form 10-Q for the quarter ended September 30, ~~2001) *10.05~~ 2001 and incorporated by reference herein)

*10.06

SCANA Supplementary Key ~~Executive~~ Severance Benefits Plan as amended July 1, 2001 (Filed as Exhibit 10.03a to Form 10-Q for the quarter ended September 30, ~~2001) *10.06~~ 2001 and incorporated by reference herein)

*10.07

SCANA Long-Term Equity Compensation Plan dated January 2000 ~~filed~~(Filed as Exhibit 4.04 to Registration Statement No. ~~333-37398) *10.07 X Request for Action~~333-37398 and incorporated by ~~the~~reference herein)

*10.08

Amendment to SCANA Long-Term Equity Compensation Plan ~~Committee of the Board dated August 1, 2002~~adopted April 29, 2004 (Filed ~~as Exhibit 10.06 to Form 10-Q for the quarter ended June 30, 2003) *10.08~~ herewith)

*10.09

Description of SCANA Whole Life Option (Filed as Exhibit 10-F to Form 10-K for the year ended December 31, 1991, under cover of Form SE, File No. ~~1-8809) *10.09~~ 1-8809 and incorporated by reference herein)

*10.10

Description of SCANA Corporation Executive Annual Incentive Plan (Filed as Exhibit 10-G to Form 10-K for the year ended December 31, 1991, under cover of Form SE, File No. ~~1-8809) 10.10~~ 1-8809 and incorporated by reference herein)

10.11

Operating Agreement of Pine Needle LNG Company, LLC dated August 8, 1995 (Filed as Exhibit 10.01 to Registration Statement No. ~~333-45206) 10.11~~ 333-45206 and incorporated by reference herein)

10.12

Amendment to Operating Agreement of Pine Needle LNG Company, LLC dated October 1, 1995 (Filed as Exhibit 10.02 to Registration Statement No. ~~333-45206) 10.12~~ 333-45206 and incorporated by reference herein)

10.13

Amended Operating Agreement of Cardinal Extension Company, LLC dated December 19, 1996 (Filed as Exhibit 10.03 to Registration Statement No. ~~333-45206) 10.13~~ 333-45206 and incorporated by reference herein)

10.14

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)~~ Exhibit Applicable to Form 10-Q of No. SCANA SCE&G PSNC Description Energy *10.15 X Form of Severance Agreement between PSNC Energy333-45206 and ~~its Executive Officers (Filed as Exhibit 10.05 to Registration Statement No. 333-45206) 10.16~~ incorporated by reference herein)

10.15

Service Agreement between PSNC ~~Energy~~ and SCANA Services, Inc., effective ~~April~~January 1, ~~2000~~2004 (Filed ~~as Exhibit 10.06 to Registration Statement No. 333-45206) 10.17~~ herewith)

10.16

Service Agreement between SCE&G and SCANA Services, Inc., effective ~~April~~January 1, ~~2002~~2004 (Filed ~~as Exhibit 10.01 to Registration Statement No. 333-101449) 31.1~~ herewith)

31.01

Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith) ~~31.2~~

31.02

Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith) ~~31.3~~

31.03

Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith) ~~31.4~~

31.04

Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith) ~~31.5~~

31.05

Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith) ~~31.6~~

31.06

Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith) ~~32.1~~

32.01

Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) ~~32.2~~

32.02

Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) ~~32.3~~

32.03

Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) ~~32.4~~

32.04

Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) ~~32.5~~

32.05

Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) ~~32.6~~

32.06

Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) * Management Contract or Compensatory Plan or Arrangement