Scana 10-Q 2005 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

 x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2005

OR

 o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES 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
	(803) 217-9000

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 Yesx Noo South Carolina Electric & Gas Company Yes x Noo  Public Service Company of North Carolina, Incorporated Yes x Noo

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

   Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

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

            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, 2005
SCANA Corporation	Without Par Value	114,483,432
South Carolina Electric & Gas Company	$4.50 Par Value	40,296,147(a)
Public Service Company of North Carolina, Incorporated	Without Par Value	1,000(a)
(a)Owned beneficially and of record by SCANA Corporation.

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

Public Service Company of North Carolina, Incorporated meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and therefore is filing this form with the reduced disclosure format allowed under General Instruction H(2).

INDEX TO FORM 10-Q

SEPTEMBER 30, 2005

PART I. FINANCIAL INFORMATION		Page
Item 1.	Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.	Quantitative and Qualitative Disclosures About Market Risk

SCANA Corporation Financial Section		3
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Income	6
	Condensed Consolidated Statements of Cash Flows	7
	Condensed Consolidated Statements of Comprehensive Income	8
	Notes to Condensed Consolidated Financial Statements	9
	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
	Quantitative and Qualitative Disclosures About Market Risk	30
South Carolina Electric & Gas Company Financial Section		32
	Condensed Consolidated Balance Sheets	33
	Condensed Consolidated Statements of Income	35
	Condensed Consolidated Statements of Cash Flows	36
	Notes to Condensed Consolidated Financial Statements	37
	Management’s Discussion and Analysis of Financial Condition and Results of Operations	46
	Quantitative and Qualitative Disclosures About Market Risk	54
Public Service Company of North Carolina, Incorporated Financial Section		55
	Condensed Consolidated Balance Sheets	56
	Condensed Consolidated Statements of Operations	58
	Condensed Consolidated Statements of Cash Flows	59
	Notes to Condensed Consolidated Financial Statements	60
	Management’s Narrative Analysis of Results of Operations	64
Item 4.	Controls and Procedures	66
PART II. OTHER INFORMATION		67
Item 1.	Legal Proceedings	67
Item 5.	Other Information	68
Item 6.	Exhibits	68
Signatures		69
Exhibit Index		70

2

SCANACORPORATION

FINANCIAL SECTION

3

PART I. FINANCIAL INFORMATION

SCANA CORPORATION

CONDENSED CONSOLIDATEDBALANCE SHEETS

(Unaudited)

	September 30,			December 31,
Millions of dollars	2005			2004
Assets
Utility Plant In Service	$	8,854		$	8,373
Accumulated depreciation and amortization		(2,623	)		(2,315	)
		6,231			6,058
Construction work in progress		171			432
Nuclear fuel, net of accumulated amortization		33			42
Acquisition adjustments		230			230
Utility Plant, Net		6,665			6,762
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $60 and $50		104			104
Assets held in trust, net - nuclear decommissioning		51			49
Investments		61			63
Nonutility Property and Investments, Net		216			216
Current Assets:
Cash and cash equivalents		171			119
Receivables, net of allowance for uncollectible accounts of $13 and $16		546			687
Receivables - affiliated companies		23			19
Inventories (at average cost):
Fuel		236			191
Materials and supplies		75			70
Emission allowances		55			9
Prepayments and other		72			52
Total Current Assets		1,178			1,147
Deferred Debits:
Environmental		25			18
Pension asset, net		299			285
Other regulatory assets		408			404
Other		167			164
Total Deferred Debits		899			871
Total	$	8,958		$	8,996

4

 

	September 30,		December 31,
Millions of dollars	2005		2004
Capitalization and Liabilities
Shareholders’ Investment:
Common equity	$	2,642	$	2,451
Preferred stock (Not subject to purchase or sinking funds)		106		106
Total Shareholders’ Investment		2,748		2,557
Preferred Stock, net (Subject to purchase or sinking funds)		8		9
Long-Term Debt, net		2,937		3,186
Total Capitalization		5,693		5,752
Current Liabilities:
Short-term borrowings		367		211
Current portion of long-term debt		184		204
Accounts payable		330		381
Accounts payable - affiliated companies		23		18
Customer deposits and customer prepayments		64		66
Taxes accrued		84		132
Interest accrued		49		51
Dividends declared		47		43
Other		106		84
Total Current Liabilities		1,254		1,190
Deferred Credits:
Deferred income taxes, net		888		879
Deferred investment tax credits		120		121
Asset retirement obligation - nuclear plant		130		124
Other asset retirement obligations		478		450
Postretirement benefits		146		142
Other regulatory liabilities		108		209
Other		141		129
Total Deferred Credits		2,011		2,054
Commitments and Contingencies (Note 6)		-		-
Total	$	8,958	$	8,996

See Notes to Condensed Consolidated Financial Statements.

5

SCANA CORPORATION

CONDENSED CONSOLIDATEDSTATEMENTS OF INCOME

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Millions of dollars, except per share amounts	2005			2004			2005			2004
Operating Revenues:
Electric	$	615		$	492		$	1,468		$	1,306
Gas - regulated		194			162			874			776
Gas - nonregulated		318			203			942			750
Total Operating Revenues		1,127			857			3,284			2,832
Operating Expenses:
Fuel used in electric generation		217			139			482			355
Purchased power		11			11			29			43
Gas purchased for resale		447			300			1,484			1,206
Other operation and maintenance		149			142			460			440
Depreciation and amortization		89			68			423			198
Other taxes		35			36			114			112
Total Operating Expenses		948			696			2,992			2,354
Operating Income		179			161			292			478
Other Income (Expense):
Other income (expense), including allowance for equity funds
used during construction of $-, $2, $- and $13		13			(5	)		39			26
Gain on sale of investments and assets		-			-			8			-
Impairment on investments		-			(25	)		-			(25	)
Interest charges, net of allowance for borrowed funds
used during construction of $1, $2, $2 and $8		(52	)		(50	)		(160	)		(151	)
Total Other Expense		(39	)		(80	)		(113	)		(150	)
Income Before Income Taxes, Earnings (Losses) from Equity
Method Investments and Preferred Stock Dividends		140			81			179			328
Income Tax Expense (Benefit)		36			24			(141	)		108
Income Before Earnings (Losses) from Equity Method		104			57			320			220
Investments and Preferred Stock Dividends
Earnings (Losses) from Equity Method Investments		(2	)		(1	)		(68	)		1
Income Before Preferred Stock Dividends		102			56			252			221
Cash Dividends on Preferred Stock of Subsidiary		2			2			6			6
Net Income	$	100		$	54		$	246		$	215
Basic and Diluted Earnings Per Share of Common Stock	$	.88		$	.48		$	2.16		$	1.93
Weighted Average Shares Outstanding (millions)		114.1			111.8			113.6			111.3
See Notes to Condensed Consolidated Financial Statements.

6

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OFCASH FLOWS

(Unaudited)

	Nine Months Ended
	September 30,
Millions of dollars	2005			2004
Cash Flows From Operating Activities:
Net income	$	246		$	215
Adjustments to reconcile net income to net cash provided from operating activities:
Losses (earnings) from equity method investments		68			(1	)
Depreciation and amortization		425			207
Amortization of nuclear fuel		4			16
Gain on sale of assets and investments		(8	)		-
Hedging activities		12			1
Impairment of investments		-			25
Allowance for equity funds used during construction		(1	)		(13	)
Carrying cost recovery		(8	)		-
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		137			124
Inventories		(125	)		(75	)
Prepayments and other		(2	)		(20	)
Pension asset		(13	)		(10	)
Other regulatory assets		31			(24	)
Deferred income taxes, net		22			80
Regulatory liabilities		(156	)		30
Postretirement benefits obligations		4			5
Accounts payable		(39	)		(94	)
Taxes accrued		(48)			(17	)
Interest accrued		(2	)		1
Changes in fuel adjustment clauses		(36	)		23
Changes in other assets		12			2
Changes in other liabilities		18			15
Net Cash Provided From Operating Activities		541			490
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(285	)		(311	)
Proceeds from sale of assets and investments		8			2
Nonutility property additions		(11	)		(15	)
Investments in affiliates and other		(26	)		(14	)
Net Cash Used For Investing Activities		(314	)		(338	)
Cash Flows From Financing Activities:
Proceeds from issuance of debt		197			124
Proceeds from issuance of common stock		66			47
Repayment of debt		(459	)		(109	)
Repurchase of common stock		-			(4	)
Redemption of preferred stock		(1	)		-
Dividends on equity securities		(134	)		(125	)
Short-term borrowings, net		156			(11	)
Net Cash Used For Financing Activities		(175	)		(78	)
Net Increase In Cash and Cash Equivalents		52			74
Cash and Cash Equivalents, January 1		119			117
Cash and Cash Equivalents, September 30	$	171		$	191
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $2 and $8)	$	163		$	151
- Income taxes		45			21
Noncash Investing and Financing Activities:
Unrealized loss on securities available for sale, net of tax		-			(1	)
Accrued construction expenditures		14			22

See Notes to Condensed Consolidated Financial Statements.

7

SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OFCOMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Millions of dollars	2005		2004		2005		2004
Net Income	$	100	$	54	$	246	$	215
Other Comprehensive Income (Loss), net of tax:
Unrealized gains (losses) on securities available for sale		-		11		-		(1	)
Unrealized gains on hedging activities		7		3		11		1
Total Comprehensive Income(1)	$	107	$	68	$	257	$	215
(1) Accumulated other comprehensive income (loss) totaled $7.7 million and $(3.8) million as of September 30, 2005 and December 31, 2004, respectively.
See Notes to Condensed Consolidated Financial Statements.

8

SCANA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2005

(Unaudited)

The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in SCANA Corporation’s (SCANA, and together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, 2004. These are interim financial statements, and due to the seasonality of the Company’s business, the amounts reported in the Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the full year. In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature, which are necessary for a fair statement of the results for the interim periods reported.

1.       SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.      Basis of Accounting

The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71,“Accounting for the Effects of Certain Types of Regulation.”SFAS 71 requires cost-based rate-regulated utilities to recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, as of September 30, 2005 the Company has recorded approximately $433 million and $586 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.

	September 30,			December 31,
Millions of dollars	2005			2004
Accumulated deferred income taxes, net	$	125		$	126
Under-collections - electric fuel and gas cost adjustment clauses, net		58			41
Deferred purchased power costs		19			26
Deferred environmental remediation costs		25			18
Asset retirement obligation - nuclear decommissioning and related funding		80			76
Other asset retirement obligations		(478	)		(450	)
Deferred synthetic fuel tax benefits, net		-			(97	)
Storm damage reserve		(37	)		(33	)
Franchise agreements		55			58
Deferred regional transmission organization costs		12			14
Other		(12)			(16)
Total	$	(153	)	$	(237	)

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

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

Deferred environmental remediation costs represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by the Company. Costs incurred at sites owned by SCE&G are being recovered through rates, of which approximately $11.9 million remain to be recovered. A portion of the costs incurred at sites owned by Public Service Company of North Carolina, Incorporated (PSNC Energy) has been recovered through rates. Amounts incurred and deferred, net of insurance settlements, that are not currently being recovered by PSNC Energy through rates are approximately $1.7 million. Management believes that these costs and the estimated remaining costs of approximately $8.7 million will be recoverable by PSNC Energy.

9

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

Other asset retirement obligations represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets.

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

The storm damage reserve represents an SCPSC approved reserve account for SCE&G capped at $50 million to be collected through rates. The accumulated storm damage reserve can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. For the nine months ended September 30, 2005, no significant amounts have been drawn from this reserve account.

Franchise agreements represent costs associated with the 30-year electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. These amounts are being amortized through cost of service rates over approximately 15 years.

Deferred regional transmission organization costs represent costs incurred by SCE&G in the United States Federal Energy Regulatory Commission (FERC)-mandated formation of GridSouth. The project was suspended in 2002. Effective January 2005, the SCPSC approved the amortization of these amounts through cost of service rates over approximately five years.

The SCPSC and the NCUC (collectively, state commissions) have reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by a state commission. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. However, ultimate recovery is subject to state commission approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company’s results of operations, liquidity or financial position in the period the write-off would be recorded.

B.      Equity Compensation Plan

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

Options, all of which were granted prior to 2003, and all of which were fully vested as of September 30, 2005, were granted with exercise prices equal to the fair market value of SCANA’s common stock on the respective grant dates; therefore, no compensation expense has been recognized in connection with such grants. If the Company had recognized compensation expense for the issuance of options based on the fair value method described in SFAS 123, pro forma net income and earnings per share would have been as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Net income - as reported (millions)	$	100	$	54	$	246	$	215
Net income - pro forma (millions)	$	100	$	54	$	246	$	214
Basic and diluted earnings per share - as reported	$	.88	$	.48	$	2.16	$	1.93
Basic and diluted earnings per share - pro forma	$	.88	$	.48	$	2.16	$	1.92

10

 The Company also grants other forms of equity-based compensation to certain employees. The value of such awards is recognized as compensation expense under APB 25. Total expense recorded for these awards was approximately $1.6 million and $6.5 million for the three and nine months ended September 30, 2005, respectively, and approximately $2.6 million and $7.4 million, respectively, for the corresponding periods ended September 30, 2004.

C.      Pension and Other Postretirement Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2005			2004			2005		2004
Three months ended September 30
Service cost	$	3.1		$	2.7		$	0.9	$	0.9
Interest cost		9.7			9.4			2.4		2.9
Expected return on assets		(19.0	)		(17.7	)		-		-
Prior service cost amortization		1.8			1.7			0.1		0.5
Transition obligation amortization		0.2			0.2			0.2		0.2
Amortization of actuarial loss		-			-			-		0.5
Net periodic benefit (income) cost	$	(4.2	)	$	(3.7	)	$	3.6	$	5.0

Nine months ended September 30
Service cost	$	9.2		$	8.3		$	2.7	$	2.4
Interest cost		28.7			28.1			8.0		8.7
Expected return on assets		(57.2	)		(53.2	)		-		-
Prior service cost amortization		5.2			4.9			0.6		1.0
Transition obligation amortization		0.6			0.6			0.6		0.6
Amortization of actuarial loss		-			-			0.9		1.5
Net periodic benefit (income) cost	$	(13.5	)	$	(11.3	)	$	12.8	$	14.2

D.      Earnings Per Share

Earnings per share amounts have been computed in accordance with SFAS 128,“Earnings Per Share.” Under SFAS 128, basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share are computed by dividing net income by the weighted average number of shares of common stock outstanding during the period, after giving effect to securities considered to be dilutive potential common stock. The Company uses the treasury stock method in determining total dilutive potential common stock. The Company has no securities that would have an antidilutive effect on earnings per share.

E.      Transactions with Affiliates

SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel. SCE&G had recorded as receivables from these affiliated companies approximately $23.5 million and $18.6 million at September 30, 2005 and December 31, 2004, respectively. SCE&G had recorded as payables to these affiliated companies approximately $23.3 million and $17.8 million at September 30, 2005 and December 31, 2004, respectively. SCE&G purchased approximately $70.2 million and $52.7 million of synthetic fuel from these affiliated companies for the three months ended September 30, 2005 and 2004, respectively. SCE&G purchased approximately $183.9 million and $142.9 million of synthetic fuel from these affiliated companies for the nine months ended September 30, 2005 and 2004, respectively.

F.      New Accounting Matters 

SFAS 154,“Accounting Changes and Error Corrections,”was issued in June 2005. It requires retrospective application to financial statements of prior periods for every voluntary change in accounting principle unless such retrospective application is impracticable. SFAS 154 replaces Accounting Principles Board (APB) Opinion 20,“Accounting Changes,” and SFAS 3,“Reporting Accounting Changes in Interim Financial Statements,” although it carries forward some of their provisions. The Company will adopt SFAS 154 in the first quarter of 2006, and does not expect that the initial adoption will have a material impact on the Company’s results of operations, cash flows or financial position.

11

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

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

G.      Reclassifications

Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2005.

2.       RATE AND OTHER REGULATORY MATTERS

  South Carolina Electric & Gas Company (SCE&G)

Electric

In a January 2005 order, the SCPSC granted SCE&G a composite increase in retail electric rates of approximately 2.89%, designed to produce additional annual revenues of approximately $41.4 million based on a test year calculation. The SCPSC lowered SCE&G's return on common equity from 12.45% to an amount not to exceed 11.4%, with rates set at 10.7%. The new rates became effective in January 2005. As part of its order, the SCPSC approved SCE&G's recovery of construction and operating costs for SCE&G's new Jasper County Electric Generating Station, recovery of costs of mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and, beginning in January 2005, the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray. Under the accounting methodology approved by the SCPSC, construction costs related to the Lake Murray Dam project were recorded in a special dam remediation account outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

In the January 2005 order, the SCPSC also approved recovery over a five-year period of SCE&G's approximately $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization and recovery through base rates over three years of approximately $25.6 million of purchased power costs that were previously deferred. As a part of its order, the SCPSC extended through 2010 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station up to $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.

12

SCE&G's rates are established using a cost of fuel component approved by the SCPSC which may be modified periodically to reflect changes in the price of fuel purchased by SCE&G. SCE&G's cost of fuel component in effect during the period January 1, 2004 through September 30, 2005 was as follows:

Rate Per KWh	Effective Date
$.01678	January-April 2004
$.01821	May-December 2004
$.01764	January-April 2005
$.02256	May-September 2005

Gas

In October 2005, the SCPSC granted SCE&G an overall increase of $22.9 million, or 5.69 percent, in retail gas base rates. The new rates are based on an allowed return on common equity of 10.25 percent, and became effective with the first billing cycle in November 2005.

SCE&G's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by SCE&G. SCE&G's cost of gas component in effect during the period January 1, 2004 through September 30, 2005 was as follows:

Rate Per Therm	Effective Date
$.877	January-October 2004
$.903	November 2004-September 2005

 In October 2005 the SCPSC approved an increase in SCE&G’s cost of gas component from a rate of $.903 per therm for all customer classes to rates of $1.29729, $1.22218 and $1.19823 per therm for residential, small and medium general service and large general service classes, respectively. These new rates are effective with the first billing cycle in November 2005. As a part of this proceeding, in order to moderate the effect of volatile natural gas prices on customers, the SCPSC approved a plan to defer certain under-collections of gas costs until November 2006.

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

PSNC Energy’s rates are established using a benchmark cost of gas approved by the NCUC, which may be modified periodically to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually.

PSNC Energy’s benchmark cost of gas in effect during the period January 1, 2004 through September 30, 2005 was as follows:

Rate Per Therm	Effective Date
$.600	January-September 2004
$.675	October-November 2004
$.825	December 2004-January 2005
$.725	February-July 2005
$.825	August-September 2005

 In September 2005 the NCUC approved PSNC Energy’s request to increase the benchmark cost of gas from $.825 per therm to $1.100 per therm for service rendered on and after October 1, 2005. In October 2005 the NCUC approved PSNC Energy’s request to increase the benchmark cost of gas from $1.100 per therm to $1.275 per therm for service rendered on and after November 1, 2005.

In September 2005, in connection with the Company’s 2005 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, 2005. The NCUC also authorized new rate decrements, effective October 1, 2005, to refund over-collections of certain gas costs included in deferred accounts.

13

 A state expansion fund, established by the North Carolina General Assembly in 1991 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 September 2005 the NCUC approved PSNC Energy’s request for disbursement of up to $1.1 million from the expansion fund to extend natural gas service to Louisburg, North Carolina. The project will be completed in 2006.

In March 2005 PSNC Energy refunded approximately $7.7 million in pipeline supplier refunds by a direct bill credit to various customers.

In January 2005 the NCUC authorized PSNC Energy to defer for subsequent rate consideration certain expenses incurred to comply with the U. S. Department of Transportation’s Pipeline Integrity Management requirements. This accounting treatment was effective November 1, 2004.

South Carolina Pipeline Corporation (SCPC)

SCPC’s purchased gas adjustment for cost recovery and gas purchasing policies are reviewed annually by the SCPSC. In a July 2005 order, the SCPSC found that for the period January through December 2004 SCPC’s gas purchasing policies and practices were prudent and SCPC properly adhered to the gas cost recovery provisions of its gas tariff.

3.       DEBT AND CREDIT FACILITIES

In September 2005 SCANA renewed $100 million in committed short-term credit facilities. The credit facilities will expire on September 26, 2006.

In June 2005 $650 million in committed five-year revolving credit facilities for SCE&G, South Carolina Fuel Company, Inc. (Fuel Company) and PSNC Energy were amended to extend the term of the existing credit facilities by an additional year. The credit facilities now will expire on June 30, 2010.

On June 15, 2005 SCE&G retired at maturity $150 million in first mortgage bonds. These bonds bore interest at 7.50%. SCE&G used available cash, together with short-term borrowings, to effect the retirement.

During the second quarter of 2005, the Company terminated two interest rate swap agreements with an aggregate notional amount of $225 million.  Under the swap agreements, the Company received fixed rate interest of 5.81% and 6.25%, and paid variable rate interest.  The termination of these swap agreements did not significantly impact the Company's results of operations, cash flows or financial position.

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

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

4.       RETAINED EARNINGS

The Company’s Restated Articles of Incorporation do not limit the dividends that may be paid on its common stock. However, the Restated Articles of Incorporation of SCE&G contain provisions that, under certain circumstances, which the Company considers to be remote, could limit the payment of cash dividends on its common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At September 30, 2005, of SCE&G’s approximately $1 billion in retained earnings, approximately $51 million were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.

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5.      FINANCIAL INSTRUMENTS

The Company utilizes various financial derivatives, including those designated as cash flow hedges related to natural gas. The Company also utilizes swap agreements to manage interest rate risk. These transactions are more fully described in Note 9 to the consolidated financial statements in SCANA’s Annual Report on Form 10-K for the year ended December 31, 2004.

The Company recognizes gains (losses) as a result of qualifying cash flow hedges whose hedged transactions occur during the reporting period and records them, net of taxes, in cost of gas. The Company recognized a gain of $2.4 million and a loss of $(0.4) million for the three and nine months ended September 30, 2005, respectively, and recognized gains of $0.3 million and $3.3 million, respectively, for the corresponding periods ended September 30, 2004. The Company estimates that most of the September 30, 2005 unrealized gain balance of $8.2 million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in 2005 and 2006 as a decrease to gas cost if market prices remain at current levels. As of September 30, 2005, all of the Company's cash flow hedges settle by their terms before the end of December 2007.

At September 30, 2005 the estimated fair value of the Company’s swaps totaled $0.3 million (gain) related to combined notional amounts of $47.4 million.

6.    COMMITMENTS AND CONTINGENCIES

Reference is made to Note 10 to the consolidated financial statements appearing in SCANA’s Annual Report on Form 10-K for the year ended December 31, 2004. Commitments and contingencies at September 30, 2005 include the following:

A.    Nuclear Insurance

The Price-Anderson Indemnification Act (the Act) deals with public liability for a nuclear incident. The Act establishes the liability limit for third-party claims associated with any nuclear incident at $10.5 billion. Each reactor licensee is currently liable for up to $100.6 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $15 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 $10 million per year.

SCE&G currently maintains policies (for itself and on behalf of the South Carolina Public Service Authority, the one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $15.8 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G’s rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident at Summer Station. However, if such an incident were to occur, it would have a material adverse impact on the Company’s results of operations, cash flows and financial position.

B.    Environmental

In March 2005 the Environmental Protection Agency (EPA) issued a final rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. SCE&G has petitioned the United States Court of Appeals for the District of Columbia Circuit to review CAIR. Several other electric utilities have filed separate petitions. The petitioners seek a change in the method CAIR uses to allocate sulfur dioxide emission allowances to a method the petitioners believe is more equitable. The Company believes that installation of additional air quality controls will be needed to meet the CAIR requirements. Compliance plans and cost to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates.

15

In March 2005 the EPA issued a final rule establishing a mercury emissions cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. The Company is reviewing the final rule. Installation of additional air quality controls is likely to be required to comply with the mercury rule’s emission caps. Compliance plans and costs to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates.

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

South Carolina Electric & Gas Company

  At SCE&G, site assessment and cleanup costs are deferred and are being recovered through rates (see Note 1). Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $11.9 million at September 30, 2005. The deferral includes the estimated costs associated with the following matters.

SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for contamination. SCE&G anticipates that the remaining remediation activities will be completed by mid-2006, with certain monitoring and retreatment activities continuing until 2011. As of September 30, 2005, SCE&G had spent approximately $21.0 million to remediate the Calhoun Park site and expects to spend an additional $0.8 million. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of approximately $9 million for certain costs and damages relating to this site. Any cost arising from this matter is expected to be recoverable through rates.

SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. One of the sites has been remediated and will undergo routine monitoring until released by the South Carolina Department of Health and Environmental Control (DHEC). The other sites are currently being investigated under work plans approved by DHEC. SCE&G anticipates that major remediation activities for the three sites will be completed in 2010. As of September 30, 2005, SCE&G had spent approximately $4.3 million related to these three sites, and expects to spend an additional $8.2 million.

SCE&G has been named, along with 27 others, by the Environmental Protection Agency (EPA) as a potentially responsible party (PRP) at the Carolina Transformer Superfund site located in Fayetteville, NC.  The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from 1967 to 1984.  During that time, SCE&G occasionally used CTC for the repair of existing transformers and the purchase of new transformers.  In 1984, EPA initiated a cleanup of PCB-contaminated soil and groundwater at the site.  EPA reports that it has spent $36 million to date.  SCE&G’s records indicated that only minimal quantities of used transformers were shipped to CTC, and it is not clear if any contained PCB-contaminated oil.  Although a basis for the allocation of clean-up costs among the 28 PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition.

 Public Service Company of North Carolina, Incorporated

The Company is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. The Company’s actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other potentially responsible parties. The Company has recorded a liability and associated regulatory asset of approximately $8.7 million, which reflects its estimated remaining liability at September 30, 2005. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates are approximately $1.7 million. Management believes that all MGP cleanup costs will be recoverable through gas rates.

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C.      Claims and Litigation

In 1999 an unsuccessful bidder for the purchase of certain propane gas assets of the Company filed suit against SCANA in Circuit Court, seeking unspecified damages. The suit alleged the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. On October 21, 2004, the jury issued an adverse verdict on this matter against SCANA for four causes of action for damages totaling $48 million.

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

Post-verdict motions were heard in November 2004 and January 2005. In April 2005, post-trial motions were decided by the Court, and the plaintiff was ordered to elect a single remedy from the multiple jury awards. In response to the April 2005 election order, the plaintiff elected a remedy with damages totaling $18 million, and the Company placed the funds in escrow with the Clerk of Court to forestall the accrual of post-judgment interest. The funds held in escrow are recorded within prepayments and other assets on the balance sheet and appear as an investing activity in the statement of cash flows. The Company believes its accrued liability is still a reasonable estimate. However, the Company continues to believe that the verdict was inconsistent with the facts presented and applicable laws. Both parties have appealed the judgment.

The Company is also defending a claim for $2.7 million for reimbursement of legal fees and expenses under an indemnification and hold harmless agreement in the contract for the sale of the propane gas assets. A bench trial on the indemnification was held on January 14, 2005, and on August 9, 2005 an order was entered against the Company in the amount of $2.6 million. The Company filed a motion and amended motion to vacate or in the alternative to alter or amend or reconsider the order and is currently awaiting a decision. The Company has made provision for this potential loss and further believes that the resolution of this claim will not have a material adverse impact on its results of operations, cash flows or financial condition.

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

On May 17, 2004, the Company was served with a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation. The case was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit (the Court). The plaintiff alleges the Company made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than the Company’s electricity-related internal communications.  The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. The plaintiff did not assert a specific dollar amount for the claims. The Company believes its actions are consistent with governing law and the applicable documents granting easements and rights-of-way. The Court granted the Company’s motion to dismiss and issued an order dismissing the case on June 29, 2005. The plaintiff has appealed. The Company intends to mount a vigorous defense and believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.

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A complaint was filed on October 22, 2003 against SCE&G by the State of South Carolina alleging that SCE&G violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality’s limits. The complaint alleged that SCE&G failed to obey, observe or comply with the lawful order of the SCPSC by charging franchise fees to those not residing within a municipality. The complaint sought restitution to all affected customers and penalties of up to $5,000 for each separate violation. The State of South Carolina v. SCE&G claim has been settled by an agreement between the parties, and the settlement has been approved by the court. The allegations were also the subject of a purported class action lawsuit filed in December 2003, against Duke Energy Corporation, Progress Energy Services Company and SCE&G (styled as Edwards v. SCE&G), but that case has been dismissed by the plaintiff. In addition, SCE&G filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to SCE&G’s electric and gas service, to approve SCE&G’s efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation that the SCPSC deems just and proper to regulate the franchise fee collection process. A hearing on this petition has not been scheduled. The Company believes that the resolution of these matters will not have a material adverse impact on its results of operations, cash flows or financial condition.

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

7.       SEGMENT OF BUSINESS INFORMATION

The Company’s reportable segments are listed in the following table. The Company uses operating income to measure profitability for its regulated operations; therefore, net income is not allocated to the Electric Operations, Gas Distribution and Gas Transmission segments. The Company uses net income to measure profitability for its Retail Gas Marketing and Energy Marketing segments. Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy which meet SFAS 131 criteria for aggregation. All Other includes equity method investments and other nonreportable segments.

	External			Intersegment			Operating			Net			Segment
Millions of dollars	Revenue			Revenue			Income (Loss)			Income (Loss)			Assets
Three Months Ended September 30, 2005
Electric Operations	$	615		$	1		$	186			n/a
Gas Distribution		140			-			(10	)		n/a
Gas Transmission		54			69			5			n/a
Retail Gas Marketing		77			-			n/a		$	(3	)
Energy Marketing		241			67			n/a			2
All Other		17			83			n/a			(1	)
Adjustments/Eliminations		(17	)		(220	)		(2	)		102
Consolidated Total	$	1,127		$	-		$	179		$	100

Nine Months Ended September 30, 2005
Electric Operations	$	1,468		$	3		$	194		n/a		$	5,315
Gas Distribution		712			-			45		n/a			1,516
Gas Transmission		162			264			17		n/a			334
Retail Gas Marketing		408			-			n/a	$	20			125
Energy Marketing		534			110			n/a		1			143
All Other		52			238			n/a		(65	)		586
Adjustments/Eliminations		(52	)		(615	)		36		290			939
Consolidated Total	$	3,284		$	-		$	292	$	246		$	8,958

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Three Months Ended September 30, 2004
Electric Operations	$	492		$	1		$	168			n/a
Gas Distribution		114			-			(11	)		n/a
Gas Transmission		48			57			3			n/a
Retail Gas Marketing		70			-			n/a		$	(1	)
Energy Marketing		133			27			n/a			1
All Other		15			78			n/a			(27	)
Adjustments/Eliminations		(15	)		(163	)		1			81
Consolidated Total	$	857		$	-		$	161		$	54

Nine Months Ended September 30, 2004
Electric Operations	$	1,306		$	3		$	385		n/a		$	5,256
Gas Distribution		622			-			38		n/a			1,424
Gas Transmission		154			238			14		n/a			316
Retail Gas Marketing		379			-			n/a	$	23			110
Energy Marketing		371			64			n/a		-			55
All Other		44			220			n/a		(21	)		678
Adjustments/Eliminations		(44	)		(525	)		41		213			870
Consolidated Total	$	2,832		$	-		$	478	$	215		$	8,709

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SCANA CORPORATION

MANAGEMENT’S DISCUSSIONAND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations appearing in SCANA Corporation’s (SCANA, and together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, 2004.

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

Electric Operations

The Energy Policy Act of 2005 (the “energy bill”) became law in August 2005.  Key provisions of the energy bill include the establishment of an electric reliability organization to enforce reliability standards for transmission systems, the restriction of standard market design (SMD) rulemaking by the Federal Energy Regulatory Commission (FERC) and the provision for continued reservation of electric transmission capacity needed to serve native load customers.  The energy bill also repeals the Public Utility Holding Company Act of 1935, and provides for greater regulatory oversight by other federal and state authorities.  The energy bill requires FERC to put in place rules and regulations to fully implement applicable provisions of the energy bill. The Company is reviewing the energy bill and related rules proposed by FERC to determine the impact they may have on the Company’s operations. In a separate development, in July 2005 FERC terminated its proposed rule for SMD.  The Company cannot predict when or if FERC will advance other regulatory initiatives related to the national energy market or what conditions such initiatives would impose on utilities.

Gas Distribution

In October 2005, the Public Service Commission of South Carolina (SCPSC) granted South Carolina Electric & Gas Company (SCE&G) an overall increase of $22.9 million, or 5.69 percent, in retail gas base rates. The new rates are based on an allowed return on common equity of 10.25 percent, and became effective with the first billing cycle in November 2005.

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

Gas Transmission

SCANA plans to merge two of its subsidiaries, South Carolina Pipeline Corporation (SCPC) and SCG Pipeline, Inc., into a new company to be called Carolina Gas Transmission Corporation (CGT). CGT will operate as an open access, transportation-only interstate pipeline company. The merger is subject to approval by FERC. SCPC is reviewing the major issues relating to the merger with its customers in an attempt to reach agreement with them prior to filing the application with FERC. SCANA does not expect a final decision regarding the merger from FERC before the summer of 2006.

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Retail Gas Marketing

In June 2005 the Georgia Public Service Commission (GPSC) voted to retain SCANA Energy as Georgia’s regulated provider of natural gas for a two-year period ending August 31, 2007, with an option by the GPSC to extend the term for an additional year. In connection with this contract extension, SCANA Energy has agreed to file financial and other information periodically with the GPSC, and such information will be available atwww.psc.state.ga.us.

SCANA Energy and SCANA's other natural gas distribution, transmission and marketing segments maintain gas inventory and also utilize forward contracts and financial instruments, including futures contracts and options, to manage their exposure to fluctuating commodity natural gas prices. As a part of this risk management process, at any given time, a portion of SCANA's projected natural gas needs has been purchased or otherwise placed under contract. Since SCANA Energy operates in a competitive market, it may be unable to sustain its current levels of customers and/or pricing, thereby reducing expected margins and profitability. Further, there can be no assurance that Georgia’s gas delivery regulatory framework will remain unchanged as dynamic market conditions evolve.

SCANA Energy, pursuant to a written agreement, has maintained a long-standing marketing alliance with Cobb Energy Management Corporation (Cobb Energy), an affiliate of Cobb Electric Membership Corporation (Cobb EMC), and other Georgia electric membership cooperatives (collectively, the EMCs) under the terms of which the parties work in an exclusive relationship to attract, retain and serve customers for SCANA Energy.  In July 2005, Southern Company Gas, the natural gas marketing affiliate of Southern Company, announced that it had signed a letter of intent to negotiate the sale of its business to a soon to be formed affiliate of Cobb EMC.  In anticipation of this proposed transaction, in October 2005, the Cobb EMC affiliate applied to the GPSC to become a licensed natural gas marketer. Also in connection with this proposed transaction, Cobb Energy, on behalf of itself and the EMCs, entered into discussions with SCANA Energy to modify the marketing alliance.

As a result of those discussions, effective October 31, 2005, SCANA Energy and the EMCs amended the marketing alliance so that, in an orderly fashion in 2006, the EMCs will transition to SCANA Energy certain call center and customer-related administrative functions, such as billing and collections, which are currently being provided to a portion of SCANA Energy’s customers by the EMCs. During the process and subsequent to the completion of the transition, certain other requirements also must be met by the EMCs until such time as the marketing alliance expires in October 2008.

SCANA Energy believes that its current customer service and billing systems have the capacity to accommodate the additional customers and that it will have the resources in place to assume responsibility for providing these services for its customers. SCANA Energy expects that the transition will have minimal impact on its customers or related customer service functions. However, as noted above, there can be no assurance that SCANA Energy will be able to maintain its current level of customers, and therefore, no assurance that its current level of profitability will be sustained.

RESULTS OF OPERATIONS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2005

AS COMPARED TO THE CORRESPONDING PERIODS IN 2004

Earnings Per Share

The Company's reported earnings are prepared in accordance with GAAP. Management believes that, in addition to reported earnings under GAAP, the Company's GAAP-adjusted net earnings from operations provides a meaningful representation of its fundamental earnings power and can aid in performing period-over-period financial analysis and comparison with peer group data. In management's opinion, GAAP-adjusted net earnings from operations is a useful indicator of the financial results of the Company's primary businesses. This measure is also a basis for management's provision of earnings guidance and growth projections, and it is used by management in making resource allocation and other budgetary and operational decisions. This non-GAAP performance measure is not intended to replace the GAAP measure of net earnings, but is offered as a supplement to it. A reconciliation of reported (GAAP) earnings per share to GAAP-adjusted net earnings from operations per share is provided in the table below:

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	Third Quarter				Year to Date
	2005		2004		2005			2004
Reported (GAAP) earnings per share	$	.88	$	.48	$	2.16		$	1.93
Add (Deduct):
Charges related to pending litigation		-		.10		-			.10
Investment impairment		-		.13		-			.13
Gain from sale of telecommunications investment		-		-		(.03	)		-
GAAP-adjusted net earnings from operations per share	$	.88	$	.71	$	2.13		$	2.16

Discussion of adjustments:

The charge related to pending litigation recognized in 2004 resulted from an unfavorable verdict in a case in which an unsuccessful bidder for the purchase of certain of SCANA’s propane gas assets in 1999 alleged breach of contract and related claims. Both parties have appealed the judgment.

The Company’s investment in Knology, Inc. (Knology) experienced an other-than-temporary impairment in 2004, resulting in a $.13 per share charge. The Company’s investment in Knology was monetized in December 2004. The 2005 realized gain on telecommunications investment of $.03 resulted from the receipt in 2005 of additional proceeds from the 2003 sale of the Company’s investment in ITC Holding Company. These additional proceeds had been held in escrow pending resolution of certain contingencies.

Management believes that all of the above adjustments are appropriate in determining the non-GAAP financial performance measure. Management utilizes such measure itself in exercising budgetary control, managing business operations and determining eligibility for incentive compensation payments. Such non-GAAP measure is based on management’s decision that the telecommunications investments are not part of the Company’s core businesses and will not be available to provide earnings on a long-term basis. The non-GAAP measure also provides a consistent basis upon which to measure performance by excluding the effects on per share earnings of transactions involving the Company’s telecommunications investments and litigation charge related to the sale of a prior business.

Third Quarter

GAAP-adjusted net earnings from operations per share increased primarily due to increases in electric margins of $.25, offset by increased depreciation and amortization expense of $.02, increased operations and maintenance expenses of $.03, increased interest expense of $.01 and the effects of dilution of $.02. Accelerated depreciation on the Lake Murray back-up dam and recognition of synthetic fuel tax credits and related items had no effect on net income, as discussed below.

Year to Date

GAAP-adjusted net earnings from operations per share decreased primarily due to increases in electric margins of $.27 and gas margins of $.06, offset by increased depreciation and amortization expense of $.14, increased operations and maintenance expenses of $.11, increased interest expense of $.05 and the effects of dilution of $.04. Accelerated depreciation on the Lake Murray back-up dam and recognition of synthetic fuel tax credits and related items had no effect on net income, as discussed below.

Recognition of Synthetic Fuel Tax Credits

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

22

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

The level of depreciation expense and related tax benefit recognized in the income statement will be equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of taxes. As a result, the balance of unrecovered costs in the dam remediation account is declining as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, they can have a significant impact on individual line items within the income statement. In addition, SCE&G is allowed to record non-cash carrying costs on the unrecovered investment, which is described further atOther Income.See also Other Matters - Synthetic Fuel. The accelerated depreciation, synthetic fuel tax credits, partnership losses and the income tax benefit arising from such losses recognized by SCE&G during 2005 are as follows:

	Recognized
Factors Increasing (Decreasing)	3rd Quarter			Year to Date
Net Income (millions)	2005			2005
Depreciation and amortization expense	$	(17.2	)	$	(200.8	)
Income tax benefits:
From synthetic fuel tax credits		12.9			168.1
From accelerated depreciation		6.6			76.8
From partnership losses		1.3			27.2
Total income tax benefits		20.8			272.1
Losses from Equity Method Investments		(3.6	)		(71.3	)
Impact on Net Income		-			-

Pension Income

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

	Third Quarter				Year to Date
Millions of dollars	2005		2004		2005		2004
Income Statement Impact:
Reduction in employee benefit costs	$	0.9	$	0.4	$	3.2	$	2.2
Other income		3.0		3.1		9.0		8.1
Balance Sheet Impact:
Reduction in capital expenditures		0.2		0.1		0.9		0.7
Component of amount due to Summer Station co-owner		0.1		0.1		0.4		0.3
Total Pension Income	$	4.2	$	3.7	$	13.5	$	11.3

For the last several years, the market value of the Company’s retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. Pension income for the third quarter and year to date 2005 increased compared to the corresponding periods in 2004, primarily as a result of positive investment returns.

23

Other Income

Included in other income is an allowance for funds used during construction (AFC). AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC for the three months ended September 30, 2005 decreased compared to the same period of 2004, primarily due to completion of the back-up dam at Lake Murray. AFC for the nine months ended September 30, 2005 decreased primarily due to completion of the Jasper County Electric Generating Station in May 2004 and the discontinuation of AFC on the back-up dam at Lake Murray effective December 31, 2004, as authorized by the January 2005 SCPSC rate order.

Also included in other income for the three and nine months ended September 30, 2005 is a recovery of carrying costs through synthetic fuel tax credits of approximately $2.8 million and $8.4 million, respectively, which was recorded under provisions of the January 2005 SCPSC rate order.

Dividends Declared

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

Declaration Date	Dividend Per Share	Record Date	Payment Date
February 17, 2005	$.39	March 10, 2005	April 1, 2005
May 5, 2005	$.39	June 10, 2005	July 1, 2005
July 27, 2005	$.39	September 9, 2005	October 1, 2005
November 2, 2005	$.39	December 9, 2005	January 1, 2006

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 (including transactions with affiliates) were as follows:

	Third Quarter							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004
Operating revenues	$	615.6		25.1	%	$	491.9	$	1,468.5		12.4	%	$	1,306.4
Less: Fuel used in generation		217.1		56.0	%		139.2		482.1		35.9	%		354.7
Purchased power		11.5		7.5	%		10.7		29.1		(32.6	)%		43.2
Margin	$	387.0		13.1	%	$	342.0	$	957.3		5.4	%	$	908.5

Third Quarter

Margin increased by $16.8 million due to favorable weather, by $12.9 million due to increased retail electric rates that went into effect in January 2005, by $7.8 million due to customer growth, and by $7.3 million in increased off-system sales.

Year to Date

Margin increased by $32.2 million due to increased retail electric rates that went into effect in January 2005, by $9.2 million due to increased off-system sales and by $18.8 million due to customer growth. These increases were offset by $12.0 million due to unfavorable weather.

24

Gas Distribution

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

	Third Quarter							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004
Operating revenues	$	139.7		22.4	%	$	114.1	$	711.0		14.1	%	$	623.0
Less: Gas purchased for resale		103.4		28.1	%		80.7		520.3		17.5	%		442.7
Margin	$	36.3		8.7	%	$	33.4	$	190.7		5.8	%	$	180.3

Third Quarter and Year to Date

Margin increased primarily due to customer growth.

Gas Transmission

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

	Third Quarter							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004
Operating revenues	$	123.1		16.2	%	$	105.9	$	426.0		8.6	%	$	392.1
Less: Gas purchased for resale		110.2		18.2	%		93.2		386.0		9.8	%		351.6
Margin	$	12.9		1.6	%	$	12.7	$	40.0		(1.2	)%	$	40.5

Third Quarter

Margin increased primarily as a result of higher margins on industrial customers.

Year to Date

Margin decreased slightly due to lower transportation volumes.

Retail Gas Marketing

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

	Third Quarter									Year to Date
Millions of dollars	2005			% Change			2004			2005		% Change			2004
Operating revenues	$	76.9			9.7	%	$	70.1		$	407.7		7.5	%	$	379.1
Net income (loss)	$	(3.0	)		*		$	(0.5	)	$	20.3		(12.5	)%	$	23.2

*Greater than 100%

Third Quarter

 Operating revenues increased primarily as a result of higher average retail prices due to higher commodity gas costs. Net loss increased primarily due to lower sales margins.

25

Year to Date

Operating revenues increased primarily as a result of higher average retail prices due to higher commodity gas costs. Net income decreased primarily due to increased bad debt expense and higher operating and customer service expenses offsetting higher margins.

Energy Marketing

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

	Third Quarter							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004
Operating revenues	$	307.7		*		$	100.6	$	644.2		48.4	%	$	434.2
Net income	$	1.9		58.3	%	$	1.2	$	0.9		*		$	0.2

* Greater than 100%

Third Quarter and Year to Date

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

Other Operating Expenses

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

	Third Quarter							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004
Other operation and maintenance	$	148.8		4.7	%	$	142.1	$	460.5		4.7	%	$	440.0
Depreciation and amortization		89.0		30.3	%		68.3		422.8		*			197.6
Other taxes		35.3		(0.8	)%		35.6		113.4		0.5	%		112.8
Total	$	273.1		11.0	%	$	246.0	$	996.7		32.8	%	$	750.4

* Greater than 100%

Third Quarter

Other operation and maintenance expenses increased primarily due to increased electric generation and gas distribution expenses of $4.3 million, increased customer billing expense of $1.0 million and higher expenses related to regulatory matters of $1.3 million and increased amortization of regulatory assets of $0.8 million. Depreciation and amortization increased approximately $17.2 million due to accelerated depreciation of the back-up dam at Lake Murray (previously explained atRecognition of Synthetic Fuel Tax Credits) and increased $1.4 million due to normal net property additions. In addition, as a result of the January 2005 rate order, SCE&G received approval to amortize previously deferred purchased power costs and to implement new depreciation rates, resulting in $4.1 million of additional depreciation and amortization expense in the period.

Year to Date

Other operation and maintenance expenses increased primarily due to increased major maintenance expenses of $7.6 million, increased expenses associated with the Jasper County Electric Generating Station which was completed in May 2004 totaling $2.5 million, increased nuclear operating and maintenance expenses of $3.4 million, higher expenses related to regulatory matters of $2.3 million and higher amortization of regulatory assets of $2.7 million. Depreciation and amortization increased approximately $200.8 million due to accelerated depreciation of the back-up dam at Lake Murray (previously explained atRecognition of Synthetic Fuel Tax Credits) and increased $6.6 million due to the completion of the Jasper County Electric Generating Station in May 2004 and $4.3 million due to normal net property changes. In addition, as a result of the January 2005 rate order, SCE&G received approval to amortize previously deferred purchased power costs and to implement new depreciation rates, resulting in $12.8 million of additional depreciation and amortization expense in the period.

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Interest Expense

Interest expense for the three and nine months ended September 30, 2005 increased primarily due to reduced AFC of $0.8 million and $5.4 million, respectively, and higher interest rates.

Income Taxes

Income tax expense for the three and nine months ended September 30, 2005 decreased primarily due to the application of synthetic fuel tax credits, as previously discussed atRecognition of Synthetic Fuel Tax Credits.

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its contractual cash obligations will be met through internally generated funds, the incurrence of additional short-term and long-term indebtedness and sales of additional equity securities. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future. The Company’s ratio of earnings to fixed charges for the 12 months ended September 30, 2005 was 2.00.

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

In a January 2005 order, the SCPSC granted SCE&G a composite increase in retail electric rates of approximately 2.89%, designed to produce additional annual revenues of approximately $41.4 million based on a test year calculation. The SCPSC lowered SCE&G's return on common equity from 12.45% to an amount not to exceed 11.4%, with rates set at 10.7%. The new rates became effective in January 2005. As part of its order, the SCPSC approved SCE&G's recovery of construction and operating costs for SCE&G's new Jasper County Electric Generating Station, recovery of costs of mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray (as previously discussed inRecognition of Synthetic Fuel Tax Credits). The SCPSC also approved recovery over a five-year period of SCE&G's approximately $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization and recovery through base rates over three years of approximately $25.6 million of purchased power costs that were previously deferred. As a part of its order, the SCPSC extended through 2010 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station up to $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 October 2005, the SCPSC granted SCE&G an overall increase of $22.9 million, or 5.69 percent, in retail gas base rates. The new rates are based on an allowed return on common equity of 10.25 percent, and became effective with the first billing cycle in November 2005.

In October 2005 the SCPSC approved an increase in SCE&G’s cost of gas component from a rate of $.903 per therm for all customer classes to rates of $1.29729, $1.22218 and $1.19823 per therm for residential, small and medium general service and large general services classes, respectively. These new rates are effective with the first billing cycle in November 2005. As a part of this proceeding, in order to moderate the effect of volatile natural gas prices on customers, the SCPSC approved a plan to defer certain under-collections of gas costs until November 2006.

27

The following table summarizes how the Company generated and used funds for property additions and construction expenditures during the nine months ended September 30, 2005 and 2004:

	Nine Months Ended
	September 30,
Millions of dollars	2005			2004
Net cash provided from operating activities	$	541		$	490
Net cash used for financing activities		(175	)		(78	)
Cash provided from sale of investments and assets		8			2
Cash and cash equivalents available at the beginning of the period		119			117
Funds used for utility property additions and construction expenditures	$	(285	)	$	(311	)
Funds used for nonutility property additions		(11	)		(15	)
Funds used for investments		(26	)		(14	)

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

CAPITAL TRANSACTIONS

In September 2005 SCANA renewed $100 million in short-term committed credit facilities. The credit facilities will expire on September 26, 2006.

In June 2005 $650 million in committed five-year revolving credit facilities for SCE&G, Fuel Company and PSNC Energy were amended to extend the term of the existing credit facilities by an additional year. The credit facilities now will expire on June 30, 2010. None of the five-year credit facilities requires the borrower to make a representation as to “no material adverse change” related to financial condition or material litigation at the time of a borrowing, and none of the facilities contains covenants based on credit ratings under which lenders could refuse to advance funds.

On June 15, 2005 SCE&G retired at maturity $150 million in first mortgage bonds. These bonds bore interest at 7.50%. SCE&G used available cash, together with short-term borrowings, to effect the retirement.

During the second quarter of 2005, the Company terminated two interest rate swap agreements with an aggregate notional amount of $225 million.  Under the swap agreements, the Company received fixed rate interest of 5.81% and 6.25%, and paid variable rate interest.  The termination of these swap agreements did not significantly impact the Company's results of operations, cash flows or financial position.

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

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

CAPITAL PROJECTS

In May 2005 SCE&G substantially completed construction of a back-up dam at Lake Murray in order to comply with new federal safety standards mandated by FERC. Construction of the project and related activities cost approximately $275 million, excluding AFC.

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ENVIRONMENTAL MATTERS

In March 2005 the Environmental Protection Agency (EPA) issued a final rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. SCE&G has petitioned the United States Court of Appeals for the District of Columbia Circuit to review CAIR. Several other electric utilities have filed separate petitions. The petitioners seek a change in the method CAIR uses to allocate sulfur dioxide emission allowances to a method the petitioners believe is more equitable. The Company believes that installation of additional air quality controls will be needed to meet the CAIR requirements. Compliance plans and cost to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates.

In March 2005 the EPA issued a final rule establishing a mercury emissions cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. The Company is reviewing the final rule. Installation of additional air quality controls is likely to be required to comply with the mercury rule’s emission caps. Compliance plans and costs to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates.

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

OTHER MATTERS

Synthetic Fuel

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

The aggregate investment in these partnerships as of September 30, 2005 is approximately $3.5 million, and through September 30, 2005, they have generated and passed through to SCE&G approximately $168.0 million in such tax credits. As previously described at Earnings Per Share, in a January 2005 order, the SCPSC approved SCE&G’s request to apply these synthetic fuel tax credits to offset the construction costs of the Lake Murray Dam project. Under the accounting methodology approved by the SCPSC, construction costs related to the project were recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation is recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

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

Depreciation on the Lake Murray Dam remediation account will be matched to available synthetic fuel tax credits on a quarterly basis until the balance in the dam remediation account is zero or until all of the available synthetic fuel tax credits have been utilized. The synthetic fuel tax credit program expires at the end of 2007.

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

29

The lower end of the inflation-adjusted benchmark range for 2004 was approximately $51 per barrel, while the upper end of that range was approximately $64. Since the reference price of oil for 2004 was less than $37, all of the synthetic fuel tax credits the Company had recorded and deferred through 2004 were available for use. While the benchmark price range for 2005 has been estimated at between $52 and $65 per barrel, the 2005 reference price will not be known until April 2006. During 2005 and subject to continuing review of the estimated benchmark range and reference price of oil for 2005, the Company intends to continue to record synthetic fuel tax credits as they are generated and to apply those credits quarterly to allow the recording of accelerated depreciation related to the balance in the dam remediation project account. The Company cannot predict what impact, if any, the price of oil may have on the Company’s ability to earn and utilize synthetic fuel tax credits in the future. However, the disruptions in the oil and gas markets in the third quarter of 2005 raise significant uncertainty as to the continued availability of the credits, particularly in 2006 and 2007.

In order to continue to earn these tax credits in future years SCANA also must be subject to a regular federal income tax liability in 2005 in an amount at least equal to the credits generated in 2005. This tax liability could be insufficient if the Company’s consolidated taxable income were to be significantly reduced as the result of realizing lower income or large deductions. Under provisions of the recently enacted energy bill, any credits generated in 2006 and 2007 in excess of the Company’s tax liability for such years would be subject to carry back or carry forward provisions. The availability of these synthetic fuel tax credits is also subject to coal availability and other operational risks related to the generating plants.

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

As noted above, the disruptions in the oil and gas markets in the third quarter of 2005 raise significant uncertainty as to the continued availability of the credits, particularly in 2006 and 2007. If it is determined that available credits are not sufficient to fully recover the construction costs of the dam remediation, regulatory action to allow recovery of those remaining costs may be sought. As of September 30, 2005, remaining unrecovered costs, based on management’s recording of accelerated deprecation and related tax benefits on its reasonable assumption that 2005’s credits will not be subjected to the phase-out provisions, were $98.3 million.

Finally, should synthetic fuel tax credit availability be curtailed under the above phase-out provisions, the level of payment Primesouth receives in connection with its operation of a synthetic fuel plant for a third party could be adversely impacted.

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QUANTITATIVE AND QUALITATIVEDISCLOSURES ABOUT MARKET RISK

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

 Interest rate risk - The table below provides information about long-term debt issued by the Company and other financial instruments that are sensitive to changes in interest rates. For debt obligations the table presents principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the figures shown reflect notional amounts and related maturities. Fair values for debt and swaps represent quoted market prices.

As of September 30, 2005			Expected Maturity Date
Millions of dollars
						There-		Fair
Liabilities	2005	2006	2007	2008	2009	After	Total	Value
Long-Term Debt:
Fixed Rate ($)	3.7	174.4	68.6	158.6	143.6	2,532.8	3,081.7	3,404.5
Average Fixed Interest Rate (%)	7.78	8.50	6.96	8.12	8.21	6.15	6.50	n/a
Variable Rate ($)				100.0			100.0	100.0
Average Variable Interest Rate (%)				4.02			4.02	n/a
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)	-	3.2	28.2	3.2	3.2	9.6	47.4	0.6
Average Pay Interest Rate (%)	-	6.63	7.28	6.63	6.63	6.63	7.02	n/a
Average Receive Interest Rate (%)	-	8.75	7.11	8.75	8.75	8.75	7.77	n/a

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

 Commodity price risk - The following table provides information about the Company’s financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 mmbtu. Fair value represents quoted market prices.

Expected Maturity:
				Options
	Futures Contracts			Purchased Call	Purchased Put	Sold Put
2005	Long ($)	Short ($)		(Long) ($)	(Short) ($)	(Long) ($)
Settlement Price(a)	14.18	14.35	Strike Price(a)	7.87	8.01	7.40
Contract Amount	7.4	1.6	Contract Amount	15.8	0.4	0.1
Fair Value	12.5	2.7	Fair Value	11.2	-	-
2006
Settlement Price(a)	13.61	14.56	Strike Price(a)	8.41	-	-
Contract Amount	11.2	11.4	Contract Amount	8.1	-	-
Fair Value	16.5	17.0	Fair Value	5.1	-	-
(a)Weighted average

Swaps	2005	2006	2007
Commodity Swaps:
Pay fixed/receive variable ($)	10.7	23.0	4.8
Average pay rate(a)	8.993	9.164	8.127
Average received rate(a)	14.112	12.945	9.943
Basis Swaps:
Pay variable/receive variable ($)	58.3	143.4	-
Average pay rate(a)	14.093	11.794	-
Average received rate(a)	14.092	11.786	-
(a)Weighted average

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SOUTH CAROLINA ELECTRIC& GAS COMPANY

FINANCIAL SECTION

32

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATEDBALANCE SHEETS

(Unaudited)

    

	September 30,			December 31,
Millions of dollars	2005			2004
Assets
Utility Plant In Service	$	7,569		$	7,096
Accumulated depreciation and amortization		(2,223	)		(1,934	)
		5,346			5,162
Construction work in progress		147			417
Nuclear fuel, net of accumulated amortization		33			42
Utility Plant, Net		5,526			5,621
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation		27			27
Assets held in trust, net - nuclear decommissioning		51			49
Investments		6			6
Nonutility Property and Investments, Net		84			82
Current Assets:
Cash and cash equivalents		14			20
Receivables, net of allowance for uncollected accounts of $2 and $1		334			267
Receivables - affiliated companies		35			19
Inventories (at average cost):
Fuel		54			35
Materials and supplies		69			64
Emission allowances		55			9
Prepayments and other		14			30
Total Current Assets		575			444
Deferred Debits:
Environmental		15			11
Pension asset, net		299			285
Due from affiliates - pension and postretirement benefits		23			23
Other regulatory assets		395			376
Other		139			138
Total Deferred Debits		871			833
Total	$	7,056		$	6,980

33

	September 30,		December 31,
Millions of dollars	2005		2004
Capitalization and Liabilities
Shareholders’ Investment:
Common equity	$	2,341	$	2,164
Preferred stock (Not subject to purchase or sinking funds)		106		106
Total Shareholders’ Investment		2,447		2,270
Preferred Stock, net (Subject to purchase or sinking funds)		8		9
Long-Term Debt, net		1,843		1,981
Total Capitalization		4,298		4,260
Minority Interest		82		81
Current Liabilities:
Short-term borrowings		350		153
Current portion of long-term debt		179		198
Accounts payable		97		106
Accounts payable - affiliated companies		95		113
Customer deposits and customer prepayments		33		32
Taxes accrued		108		152
Interest accrued		30		35
Dividends declared		40		38
Other		53		44
Total Current Liabilities		985		871
Deferred Credits:
Deferred income taxes, net		743		744
Deferred investment tax credits		119		119
Asset retirement obligation - nuclear plant		130		124
Other asset retirement obligations		385		363
Due to affiliates - pension and postretirement benefits		13		14
Postretirement benefits		146		142
Other regulatory liabilities		85		198
Other		70		64
Total Deferred Credits		1,691		1,768
Commitments and Contingencies (Note 5)		-		-
Total	$	7,056	$	6,980

See Notes to Condensed Consolidated Financial Statements.

34

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATEDSTATEMENTS OF INCOME

(Unaudited)

	Three Months Ended							Nine Months Ended
	September 30,							September 30,
Millions of dollars		2005			2004			2005			2004
Operating Revenues:
Electric		$	616		$	493		$	1,471		$	1,310
Gas			80			62			321			275
Total Operating Revenues			696			555			1,792			1,585
Operating Expenses:
Fuel used in electric generation			217			139			482			355
Purchased power			12			11			29			43
Gas purchased for resale			68			51			260			217
Other operation and maintenance			111			103			332			315
Depreciation and amortization			78			57			389			164
Other taxes			32			32			103			102
Total Operating Expenses			518			393			1,595			1,196
Operating Income			178			162			197			389
Other Income (Expense):
Other income, including allowance for equity funds			7			5			19			20
used during construction of $-, $2, $- and $11
Interest charges, net of allowance for borrowed funds
used during construction of $1, $2, $2 and $7			(35	)		(34	)		(109	)		(104	)
Gain on sale of assets			-			-			1			-
Total Other Expense			(28	)		(29	)		(89	)		(84	)
Income Before Income Taxes, Losses from Equity Method
Investments, Minority Interest and Preferred Stock Dividends			150			133			108			305
Income Tax Expense (Benefit)			39			46			(166	)		104
Income Before Losses from Equity Method Investments,
Minority Interest and Preferred Stock Dividends			111			87			274			201
Losses from Equity Method Investments			(4	)		-			(72	)		(1	)
Minority Interest			1			2			4			5
Net Income			106			85			198			195
Preferred Stock Cash Dividends Declared			2			2			6			6
Earnings Available for Common Shareholder		$	104		$	83		$	192		$	189
See Notes to Condensed Consolidated Financial Statements.

35

SOUTH CAROLINA ELECTRIC & GAS COMPANY

 CONDENSED CONSOLIDATEDSTATEMENTS OF CASH FLOWS

(Unaudited)	Nine Months Ended
	September 30,
Millions of dollars	2005			2004
Cash Flows From Operating Activities:
Net income	$	198		$	195
Adjustments to reconcile net income to net cash provided from operating activities:
Losses from equity method investments		72			1
Minority interest		4			5
Depreciation and amortization		389			164
Amortization of nuclear fuel		4			16
Allowance for equity funds used during construction		-			(11	)
Carrying cost recovery		(8	)		-
Gain on sale of assets		(1	)		-
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		(83	)		43
Inventories		(98	)		(35	)
Prepayments		16			(6	)
Pension asset		(13	)		(10	)
Other regulatory assets		27			(23	)
Deferred income taxes, net		11			52
Regulatory liabilities		(163	)		27
Postretirement benefits obligations		4			5
Accounts payable		(15	)		(95	)
Taxes accrued		(44	)		(33	)
Interest accrued		(5	)		(2	)
Changes in fuel adjustment clauses		(46	)		30
Changes in other assets		(13	)		(5	)
Changes in other liabilities		3			14
Net Cash Provided From Operating Activities		239			332
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(247	)		(269	)
Increase in nonutility property		-			(5	)
Proceeds from sale of assets		1			2
Investments in affiliates		(14	)		(14	)
Net Cash Used For Investing Activities		(260	)		(286	)
Cash Flows From Financing Activities:
Proceeds from issuance of debt		97			124
Repayment of debt		(253	)		(102	)
Redemption of preferred stock		(1	)		-
Dividends on equity securities		(117	)		(124	)
Distribution to parent		-			(29	)
Contribution from parent		95			21
Short-term borrowings - affiliate, net		(3	)		(5	)
Short-term borrowings, net		197			25
Net Cash Provided From (Used For) Financing Activities		15			(90	)
Net Decrease In Cash and Cash Equivalents		(6	)		(44	)
Cash and Cash Equivalents, January 1		20			56
Cash and Cash Equivalents, September 30	$	14		$	12
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $2 and $7)	$	103		$	100
- Income taxes		23			30
Non Cash Investing and Financing Activities:
Accrued construction expenditures		12			21
See Notes to Condensed Consolidated Financial Statements.

36

SOUTH CAROLINA ELECTRIC & GAS COMPANY

NOTES TOCONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2005

(Unaudited)

  The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in South Carolina Electric & Gas Company’s (SCE&G, and together with its consolidated affiliates, the Company) Annual Report on Form 10-K for the year ended December 31, 2004. These are interim financial statements, and due to the seasonality of the Company’s business, the amounts reported in the Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the full 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

Financial Accounting Standards Board Interpretation No. 46 (Revised 2003) (FIN 46),“Consolidation of Variable Interest Entities,” requires an enterprise’s consolidated financial statements to include entities in which the enterprise has a controlling financial interest. SCE&G has determined that it has a controlling financial interest in South Carolina Generating Company, Inc. (GENCO) and South Carolina Fuel Company, Inc. (Fuel Company), and accordingly, the accompanying condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA Corporation (SCANA), the Company’s parent. Accordingly, GENCO’s and Fuel Company’s equity and results of operations are reflected as minority interest in the Company’s condensed consolidated financial statements.

GENCO owns and operates a coal-fired electric generating station with a 615 megawatt net generating capacity (summer rating). GENCO’s electricity is sold solely to SCE&G under the terms of a power purchase and related operating agreement. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and sulfur dioxide emission allowances. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $261 million) serves as collateral for its long-term borrowings.

B.    Basis of Accounting

The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71,“Accounting for the Effects of Certain Types of Regulation.”SFAS 71 requires cost-based rate-regulated utilities to recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, as of September 30, 2005, the Company has recorded approximately $410 million and $470 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.

	September 30,			December 31,
Millions of dollars	2005			2004
Accumulated deferred income taxes, net	$	122		$	121
Under-collections - electric fuel and gas cost adjustment clauses, net		58			31
Deferred purchased power costs		19			26
Deferred environmental remediation costs		15			11
Asset retirement obligation - nuclear decommissioning and related funding		80			76
Other asset retirement obligations		(385	)		(363	)
Deferred synthetic fuel tax benefits, net		-			(97	)
Storm damage reserve		(37	)		(33	)
Franchise agreements		55			58
Deferred regional transmission organization costs		12			14
Other		1			(18)
Total	$	(60	)	$	(174	)

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

Deferred purchased power costs - represents costs that were necessitated by outages at two of SCE&G’s base load generating plants in winter 2000-2001. The SCPSC approved recovery of these costs in base rates over three years beginning in January 2005.

Deferred environmental remediation costs represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by SCE&G. Costs incurred by SCE&G at such sites are being recovered through rates, of which approximately $11.9 million remain.

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

Other asset retirement obligations represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets.

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

The storm damage reserve represents an SCPSC approved reserve account capped at $50 million to be collected through rates. The accumulated storm damage reserve can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. For the nine months ended September 30, 2005, no significant amounts have been drawn from this reserve account.

Franchise agreements represent costs associated with the 30-year electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. These amounts are being amortized through cost of service rates over approximately 15 years.

Deferred regional transmission organization costs represent costs incurred by SCE&G in the United States Federal Energy Regulatory Commission (FERC)-mandated formation of GridSouth. The project was suspended in 2002. Effective January 2005, the SCPSC approved the amortization of these amounts through cost of service rates over approximately five years.

The SCPSC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by the SCPSC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by SCE&G. However, ultimate recovery is subject to SCPSC approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company’s results of operations, liquidity or financial position in the period the write-off would be recorded.

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C.      Transactions with Affiliates

SCE&G has entered into agreements with certain affiliates to purchase all gas for resale to its distribution customers and to purchase electric energy. SCE&G purchases natural gas for resale and for electric generation from South Carolina Pipeline Corporation (SCPC) and had approximately $24.7 million and $49.5 million payable to SCPC for such gas purchases at September 30, 2005 and December 31, 2004, respectively.

SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel. The Company had recorded as receivables from these affiliated companies approximately $23.5 million and $18.6 million at September 30, 2005 and December 31, 2004, respectively. SCE&G had recorded as payables to these affiliated companies approximately $23.3 million and $17.8 million at September 30, 2005 and December 31, 2004, respectively. SCE&G purchased approximately $70.2 million and $52.7 million of synthetic fuel from these affiliated companies for the three months ended September 30, 2005 and 2004, respectively. SCE&G purchased approximately $183.9 million and $142.9 million of synthetic fuel from these affiliated companies for the nine months ended September 30, 2005 and 2004, respectively.

In the nine months ended September 30, 2005, the Company purchased approximately 342 miles of gas distribution pipeline from SCPC at its net book value, which totaled approximately $20.9 million.

D.      Pension and Other Postretirement Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2005			2004			2005			2004
Three months ended September 30
Service cost	$	3.1		$	2.7		$	0.9		$	0.9
Interest cost		9.7			9.4			2.4			2.9
Expected return on assets		(19.0	)		(17.7	)		-			-
Prior service cost amortization		1.8			1.7			0.1			0.5
Transition obligation amortization		0.2			0.2			0.2			0.2
Amortization of actuarial loss		-			-			-			0.5
Amount attributable to Company affiliates		(0.5	)		(0.5	)		(1.0	)		(1.4	)
Net periodic benefit (income) cost	$	(4.7	)	$	(4.2	)	$	2.6		$	3.6

Nine months ended September 30
Service cost	$	9.2		$	8.3		$	2.7		$	2.4
Interest cost		28.7			28.1			8.0			8.7
Expected return on assets		(57.2	)		(53.2	)		-			-
Prior service cost amortization		5.2			4.9			0.6			1.0
Transition obligation amortization		0.6			0.6			0.6			0.6
Amortization of actuarial loss		-			-			0.9			1.5
Amount attributable to Company affiliates		(1.4	)		(1.3	)		(3.6	)		(4.1	)
Net periodic benefit (income) cost	$	(14.9	)	$	(12.6	)	$	9.2		$	10.1

E.      Equity Compensation Plan

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

39

 Options, all of which were granted prior to 2003, and all of which were fully vested as of September 30, 2005, were granted with exercise prices equal to the fair market value of SCANA’s common stock on the respective grant dates; therefore, no compensation expense has been recognized in connection with such grants. If SCANA had recognized compensation expense for the issuance of options based on the fair value method described in SFAS 123, the Company’s pro forma net income would have been unchanged from net income as reported for each of the three and nine month periods ended September 30, 2005 and 2004.

SCANA also grants other forms of equity-based compensation to certain employees of the Company. The value of such awards is recognized as compensation expense under APB 25. Total expense recorded for these awards was approximately $1.2 million and $4.3 million for the three and nine months ended September 30, 2005, respectively, and approximately $1.7 million and $4.7 million for the corresponding periods ended September 30, 2004, respectively.

F.      New Accounting Matters

SFAS 154,“Accounting Changes and Error Corrections,”was issued in June 2005. It requires retrospective application to financial statements of prior periods for every voluntary change in accounting principle unless such retrospective application is impracticable. SFAS 154 replaces Accounting Principles Board (APB) Opinion 20,“Accounting Changes,” and SFAS 3,“Reporting Accounting Changes in Interim Financial Statements,” although it carries forward some of their provisions. The Company will adopt SFAS 154 in the first quarter of 2006, and does not expect that the initial adoption will have a material impact on the Company’s results of operations, cash flows or financial position.

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

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

G.      Reclassifications

Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2005.

40

2. RATE AND OTHER REGULATORY MATTERS

        Electric

In a January 2005 order, the SCPSC granted SCE&G a composite increase in retail electric rates of approximately 2.89%, designed to produce additional annual revenues of approximately $41.4 million based on a test year calculation. The SCPSC lowered SCE&G's return on common equity from 12.45% to an amount not to exceed 11.4%, with rates set at 10.7%. The new rates became effective in January 2005. As part of its order, the SCPSC approved SCE&G's recovery of construction and operating costs for SCE&G's new Jasper County Electric Generating Station, recovery of costs of mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and, beginning in January 2005, the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray. Under the accounting methodology approved by the SCPSC, construction costs related to the Lake Murray Dam project were recorded in a special dam remediation account outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

In the January 2005 order, the SCPSC also approved recovery over a five-year period of SCE&G's approximately $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization and recovery through base rates over three years of approximately $25.6 million of purchased power costs that were previously deferred. As a part of its order, the SCPSC extended through 2010 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station up to $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.

SCE&G's rates are established using a cost of fuel component approved by the SCPSC which may be modified periodically to reflect changes in the price of fuel purchased by SCE&G. SCE&G's cost of fuel component in effect during the period January 1, 2004 through September 30, 2005 was as follows:

Rate Per KWh	Effective Date
$.01678	January-April 2004
$.01821	May-December 2004
$.01764	January-April 2005
$.02256	May-September 2005

Gas

   In October 2005, the SCPSC granted SCE&G an overall increase of $22.9 million, or 5.69 percent, in retail gas base rates. The new rates are based on an allowed return on common equity of 10.25 percent, and became effective with the first billing cycle in November 2005.

SCE&G's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by SCE&G. SCE&G's cost of gas component in effect during the period January 1, 2004 through September 30, 2005 was as follows:

Rate Per Therm	Effective Date
$.877	January-October 2004
$.903	November 2004-September 2005

In October 2005 the SCPSC approved an increase in SCE&G’s cost of gas component from a rate of $.903 per therm for all customer classes to rates of $1.29729, $1.22218 and $1.19823 per therm for residential, small and medium general service and large general service classes, respectively. These new rates are effective with the first billing cycle in November 2005. As a part of this proceeding, in order to moderate the effect of volatile natural gas prices on customers, the SCPSC approved a plan to defer certain under-collections of gas costs until November 2006.

41

3.       DEBT AND CREDIT FACILITIES

In June 2005 $525 million in committed five-year revolving credit facilities for SCE&G and Fuel Company were amended to extend the term of the existing credit facilities by an additional year. The credit facilities now will expire on June 30, 2010.

On June 15, 2005 SCE&G retired at maturity $150 million in first mortgage bonds. These bonds bore interest at 7.50%. SCE&G used available cash, together with short-term borrowings, to effect the retirement.

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

4.       RETAINED EARNINGS

SCE&G’s Restated Articles of Incorporation contain provisions that, under certain circumstances, which SCE&G considers remote, could limit the payment of cash dividends on its common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At September 30, 2005, of SCE&G’s approximately $1 billion in retained earnings, approximately $51 million were restricted by this requirement as to payment of cash dividends on common stock.

5.      COMMITMENTS AND CONTINGENCIES

Reference is made to Note 10 to the consolidated financial statements appearing in SCE&G’s Annual Report on Form 10-K for the year ended December 31, 2004. Commitments and contingencies at September 30, 2005 include the following:

A. Nuclear Insurance

The Price-Anderson Indemnification Act (the Act) deals with public liability for a nuclear incident. The Act establishes the liability limit for third party claims associated with any nuclear incident at $10.5 billion. Each reactor licensee is currently liable for up to $100.6 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $15 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 $10 million per year.

SCE&G currently maintains policies (for itself and on behalf of the South Carolina Public Service Authority, the one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $15.8 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G’s rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident at Summer Station. However, if such an incident were to occur, it would have a material adverse impact on the Company’s results of operations, cash flows and financial position.

42

B.  Environmental

In March 2005 the Environmental Protection Agency (EPA) issued a final rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. SCE&G has petitioned the United States Court of Appeals for the District of Columbia Circuit to review CAIR. Several other electric utilities have filed separate petitions. The petitioners seek a change in the method CAIR uses to allocate sulfur dioxide emission allowances to a method the petitioners believe is more equitable. The Company believes that installation of additional air quality controls will be needed to meet the CAIR requirements. Compliance plans and cost to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates.

In March 2005 the EPA issued a final rule establishing a mercury emissions cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. The Company is reviewing the final rule. Installation of additional air quality controls is likely to be required to comply with the mercury rule’s emission caps. Compliance plans and costs to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates.

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

At SCE&G, site assessment and cleanup costs are deferred and are being recovered through rates (see Note 1). Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $11.9 million at September 30, 2005. The deferral includes the estimated costs associated with the following matters.

SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for contamination. SCE&G anticipates that the remaining remediation activities will be completed by mid-2006, with certain monitoring and retreatment activities continuing until 2011. As of September 30, 2005, SCE&G had spent approximately $21.0 million to remediate the Calhoun Park site and expects to spend an additional $0.8 million. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of approximately $9 million for certain costs and damages relating to this site. Any cost arising from this matter is expected to be recoverable through rates.

SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. One of the sites has been remediated and will undergo routine monitoring until released by the South Carolina Department of Health and Environmental Control (DHEC). The other sites are currently being investigated under work plans approved by DHEC. SCE&G anticipates that major remediation activities for the three sites will be completed in 2010. As of September 30, 2005, SCE&G had spent approximately $4.3 million related to these three sites, and expects to spend an additional $8.2 million.

SCE&G has been named, along with 27 others, by the Environmental Protection Agency (EPA) as a potentially responsible party (PRP) at the Carolina Transformer Superfund site located in Fayetteville, NC.  The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from 1967 to 1984.  During that time, SCE&G occasionally used CTC for the repair of existing transformers and the purchase of new transformers.  In 1984, EPA initiated a cleanup of PCB-contaminated soil and groundwater at the site.  EPA reports that it has spent $36 million to date.  SCE&G’s records indicated that only minimal quantities of used transformers were shipped to CTC, and it is not clear if any contained PCB-contaminated oil.  Although a basis for the allocation of clean-up costs among the 28 PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition.

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C.      Claims and Litigation

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

On May 17, 2004, SCE&G was served with a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation. The case was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit (the Court). The plaintiff alleges that SCE&G made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. The plaintiff did not assert a specific dollar amount for the claims. SCE&G believes its actions are consistent with governing law and the applicable documents granting easements and rights-of-way. The Court granted SCE&G’s motion to dismiss and issued an order dismissing the case on June 29, 2005. The plaintiff has appealed. SCE&G intends to mount a vigorous defense and believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.

A complaint was filed on October 22, 2003 against SCE&G by the State of South Carolina alleging that SCE&G violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality’s limits. The complaint alleged that SCE&G failed to obey, observe or comply with the lawful order of the SCPSC by charging franchise fees to those not residing within a municipality. The complaint sought restitution to all affected customers and penalties up to $5,000 for each separate violation. The State of South Carolina v. SCE&G claim has been settled by an agreement between the parties, and the settlement has been approved by the court. The allegations were also the subject of a purported class action lawsuit filed in December 2003, against Duke Energy Corporation, Progress Energy Services Company and SCE&G (styled as Edwards v. SCE&G), but that case has been dismissed by the plaintiff. In addition, SCE&G filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to SCE&G’s electric and gas service, to approve SCE&G’s efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation that the SCPSC deems just and proper to regulate the franchise fee collection process. A hearing on this petition has not been scheduled. The Company believes that the resolution of these matters will not have a material adverse impact on its results of operations, cash flows or financial condition.

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

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6.       SEGMENT OF BUSINESS INFORMATION

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

	2005									2004
			Operating			Net						Operating			Net
	External		Income			Income			Segment	External		Income			Income		Segment
Millions of Dollars	Revenue		(Loss)			(Loss)			Assets	Revenue		(Loss)			(Loss)		Assets
Three Months Ended September 30,
Electric Operations	$	616	$	186			n/a			$	493	$	168			n/a
Gas Distribution		80		(7	)		n/a				62		(4	)		n/a
All Other		-		-		$	(3	)			-		-			-
Adjustments/Eliminations		-		(1	)		107				-		(2	)	$	83
Consolidated Total	$	696	$	178		$	104			$	555	$	162		$	83

Nine Months Ended September 30,
Electric Operations	$	1,471	$	194			n/a		$	5,315	$	1,310	$	385			n/a		$	5,256
Gas Distribution		321		5			n/a			388		275		6			n/a			340
All Other		-		-		$	(72	)		3		-		-		$	(1	)		3
Adjustments/Eliminations		-		(2	)		264			1,350		-		(2	)		190			1,198
Consolidated Total	$	1,792	$	197		$	192		$	7,056	$	1,585	$	389		$	189		$	6,797

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

MANAGEMENT’S DISCUSSIONAND 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, and together with its consolidated affiliates, the Company) Annual Report on Form 10-K for the year ended December 31, 2004.

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

Electric Operations

 The Energy Policy Act of 2005 (the “energy bill”) became law in August 2005.  Key provisions of the energy bill include the establishment of an electric reliability organization to enforce reliability standards for transmission systems, the restriction of standard market design (SMD) rulemaking by the Federal Energy Regulatory Commission (FERC) and the provision for continued reservation of electric transmission capacity needed to serve native load customers.  The energy bill also repeals the Public Utility Holding Company Act of 1935, and provides for greater regulatory oversight by other federal and state authorities.  The energy bill requires FERC to put in place rules and regulations to fully implement applicable provisions of the energy bill. The Company is reviewing the energy bill and related rules proposed by FERC to determine the impact they may have on the Company’s operations. In a separate development, in July 2005 FERC terminated its proposed rule for SMD.  The Company cannot predict when or if FERC will advance other regulatory initiatives related to the national energy market or what conditions such initiatives would impose on utilities.

Gas Distribution

In October 2005, the Public Service Commission of South Carolina (SCPSC) granted South Carolina Electric & Gas Company (SCE&G) an overall increase of $22.9 million, or 5.69 percent, in retail gas base rates. The new rates are based on an allowed return on common equity of 10.25 percent, and became effective with the first billing cycle in November 2005.

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

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RESULTS OF OPERATIONS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2005

AS COMPARED TO THE CORRESPONDING PERIODS IN 2004

Net Income

Net income was as follows:

	Third Quarter				Year to Date
Millions of dollars	2005		2004		2005		2004
Net income	$	105.9	$	84.4	$	197.9	$	195.0

Third Quarter

Net income increased by approximately $28.0 million due to increases in electric margins. This increase was partially offset by approximately $0.7 million due to increased interest expense, $0.9 million due to depreciation and $4.1 million due to other operating expenses. In addition, as a result of the January 2005 rate order, SCE&G received approval to amortize previously deferred purchased power costs resulting in $1.3 million of additional depreciation expense in the period. Accelerated depreciation on the Lake Murray back-up dam and recognition of synthetic fuel tax credits and related items had no effect on net income, as discussed below.

Year to Date

Net income increased by approximately $29.7 million due to increases in electric margins and $1.9 million due to increases in gas margins. These increases were partially offset by approximately $5.6 million due to higher depreciation and operating expenses related to the Jasper County Electric Generating Station, $3.0 million due to increased interest expense, $2.6 million due to depreciation of normal property additions and $9.4 million due to other operating expenses. In addition, as a result of the January 2005 rate order, SCE&G received approval to amortize previously deferred purchased power costs and to implement new depreciation rates, resulting in $7.9 million of additional depreciation expense in the period. Accelerated depreciation on the Lake Murray back-up dam and recognition of synthetic fuel tax credits and related items had no effect on net income, as discussed below.

Recognition of Synthetic Fuel Tax Credits

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

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

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   The level of depreciation expense and related tax benefit recognized in the income statement will be equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of taxes. As a result, the balance of unrecovered costs in the dam remediation account is declining as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, they can have a significant impact on individual line items within the income statement. In addition, SCE&G is allowed to record non-cash carrying costs on the unrecovered investment, which is described further atOther Income. See also Other Matters - Synthetic Fuel. The accelerated depreciation, synthetic fuel tax credits, partnership losses and the income tax benefit arising from such losses recognized by SCE&G during 2005 are as follows:

Factors Increasing (Decreasing) Net Income (millions)	Recognized 3rd Quarter 2005			Year to Date 2005
Depreciation and amortization expense	$	(17.2	)	$	(200.8	)
Income tax benefits:
From synthetic fuel tax credits		12.9			168.1
From accelerated depreciation		6.6			76.8
From partnership losses		1.3			27.2
Total income tax benefits		20.8			272.1
Losses from Equity Method Investments		(3.6	)		(71.3	)
Impact on Net Income		-			-

Pension Income

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

	Third Quarter				Year to Date
Millions of dollars	2005		2004		2005		2004
Income Statement Impact:
Reduction in employee benefit costs	$	1.2	$	0.8	$	4.2	$	3.1
Other income		3.0		3.2		9.1		8.3
Balance Sheet Impact:
Reduction in capital expenditures		0.3		0.2		1.2		0.9
Component of amount due to Summer Station co-owner		0.1		0.1		0.4		0.3
Total Pension Income	$	4.6	$	4.3	$	14.9	$	12.6

For the last several years, the market value of SCANA’s retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. The Company’s portion of SCANA’s pension income for the third quarter and year to date 2005 increased compared to the corresponding periods in 2004, primarily as a result of positive investment returns.

Other Income

Included in other income is an allowance for funds used during construction (AFC). AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC for the three months ended September 30, 2005 decreased compared to the same period of 2004, primarily due to completion of the back-up dam at Lake Murray. AFC for the nine months ended September 30, 2005 decreased primarily due to completion of the Jasper County Electric Generating Station in May 2004 and the discontinuation of AFC on the back-up dam at Lake Murray effective December 31, 2004, as authorized by the January 2005 SCPSC rate order.

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Also included in other income for the three and nine months ended September 30, 2005 is a recovery of carrying costs through synthetic fuel tax credits of approximately $2.8 million and $8.4 million, respectively, which was recorded under provisions of the January 2005 SCPSC rate order.

Dividends Declared

SCE&G’s Board of Directors has declared the following dividends on common stock held by SCANA during 2005:

Declaration Date	Amount	Quarter Ended	Payment Date
February 17, 2005	$38.0 million	March 31, 2005	April 1, 2005
May 5, 2005	$38.0 million	June 30, 2005	July 1, 2005
July 27, 2005	$38.0 million	September 30, 2005	October 1, 2005
November 2, 2005	$38.0 million	December 31, 2005	January 1, 2006

Electric Operations

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

	Third Quarter							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004
Operating revenues	$	617.0		25.2	%	$	493.0	$	1,471.0		12.3	%	$	1,309.5
Less: Fuel used in generation		217.1		56.0	%		139.2		482.1		35.9	%		354.7
Purchased power		11.5		7.5	%		10.7		29.1		(32.6	)%		43.2
Margin	$	388.4		13.2	%	$	343.1	$	959.8		5.3	%	$	911.6

Third Quarter

Margin increased by $16.8 million due to favorable weather, by $12.9 million due to increased retail electric rates that went into effect in January 2005, by $7.8 million due to customer growth, and by $7.3 million in increased off-system sales.

Year to Date

Margin increased by $32.2 million due to increased retail electric rates that went into effect in January 2005, by $9.2 million due to increased off-system sales and by $18.8 million due to customer growth. These increases were offset by $12.0 million due to unfavorable weather.

Gas Distribution

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

	Third Quarter							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004
Operating revenues	$	80.0		30.1	%	$	61.5	$	321.3		16.8	%	$	275.1
Less: Gas purchased for resale		68.0		34.7	%		50.5		259.6		19.9	%		216.6
Margin	$	12.0		9.1	%	$	11.0	$	61.7		5.5	%	$	58.5

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 Third Quarter and Year to Date

Margin increased primarily due to customer growth.

Other Operating Expenses

Other operating expenses were as follows:

	Third Quarter							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004
Other operation and maintenance	$	111.4		8.3	%	$	102.9	$	332.3		5.5	%	$	315.1
Depreciation and amortization		77.8		36.0	%		57.2		389.0		*			164.6
Other taxes		32.0		(0.6	)%		32.2		102.9		1.0	%		101.9
Total	$	221.2		15.0	%	$	192.3	$	824.2		41.7	%	$	581.6

*Greater than 100%

Third Quarter

Other operation and maintenance expenses increased primarily due to increased electric generation and gas distribution expenses of $4.3 million, increased customer billing expense of $1.0 million, higher expenses related to regulatory matters of $1.3 million and increased amortization of regulatory assets of $0.8 million. Depreciation and amortization increased approximately $17.2 million due to accelerated depreciation of the back-up dam at Lake Murray (previously explained atRecognition of Synthetic Fuel Tax Credits) and increased $1.4 million due to normal net property additions. In addition, as a result of the January 2005 rate order, SCE&G received approval to amortize previously deferred purchased power costs and to implement new depreciation rates, resulting in $4.1 million of additional depreciation and amortization expense in the period.

Year to Date

Other operation and maintenance expenses increased primarily due to increased major maintenance expenses of $7.6 million, increased expenses associated with the Jasper County Electric Generating Station completed in May 2004 totaling $2.5 million, increased nuclear operating and maintenance expenses of $3.4. million, higher expenses related to regulatory matters of $2.3 million and higher amortization of regulatory assets of $2.7 million. Depreciation and amortization increased approximately $200.8 million due to accelerated depreciation of the back-up dam at Lake Murray (previously explained atRecognition of Synthetic Fuel Tax Credits) and increased $6.6 million due to the completion of the Jasper County Electric Generating Station in May 2004 and $4.3 million due to normal net property changes. In addition, as a result of the January 2005 rate order, SCE&G received approval to amortize previously deferred purchased power costs and to implement new depreciation rates, resulting in $12.8 million of additional depreciation and amortization expense in the period.

Interest Expense

Interest expense for the three and nine months ended September 30, 2005 increased primarily due to reduced AFC of $0.8 million and $5.4 million, respectively.

Income Taxes

Income tax expense for the three and nine months ended September 30, 2005 decreased primarily due to the application of synthetic fuel tax credits, as previously discussed atRecognition of Synthetic Fuel Tax Credits.

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LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its contractual cash obligations will be met through internally generated funds and the incurrence of additional short-term and long-term indebtedness. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future. The Company’s ratio of earnings to fixed charges for the 12 months ended September 30, 2005 was 1.95.

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

In a January 2005 order the SCPSC granted SCE&G a composite increase in retail electric rates of approximately 2.89%, designed to produce additional annual revenues of approximately $41.4 million based on a test year calculation. The SCPSC lowered SCE&G's return on common equity from 12.45% to an amount not to exceed 11.4%, with rates set at 10.7%. The new rates became effective in January 2005. As part of its order, the SCPSC approved SCE&G's recovery of construction and operating costs for SCE&G's new Jasper County Electric Generating Station, recovery of costs of mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray (as previously discussed inRecognition of Synthetic Fuel Tax Credits). The SCPSC also approved recovery over a five-year period of SCE&G's approximately $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization and recovery through base rates over three years of approximately $25.6 million of purchased power costs that were previously deferred. As a part of its order, the SCPSC extended through 2010 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station up to $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 October 2005, the SCPSC granted SCE&G an overall increase of $22.9 million, or 5.69 percent, in retail gas base rates. The new rates are based on an allowed return on common equity of 10.25 percent, and became effective with the first billing cycle in November 2005.

In October 2005 the SCPSC approved an increase in the SCE&G’s cost of gas component from a rate of $.903 per therm for all customer classes to rates of $1.29729, $1.22218 and $1.19823 per therm for residential, small and medium general service and large general services classes, respectively. These new rates are effective with the first billing cycle in November 2005. As a part of this proceeding, in order to moderate the effect of volatile natural gas prices on customers, the SCPSC approved a plan to defer certain under-collections of gas costs until November 2006.

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The following table summarizes how SCE&G generated and used funds for property additions and construction expenditures during the nine months ended September 30, 2005 and 2004:

	Nine Months Ended
	September 30,
Millions of dollars	2005			2004
Net cash provided from operating activities	$	239		$	332
Net cash provided from (used for) financing activities		15			(90	)
Cash provided from sale of assets		1			2
Cash and cash equivalents available at the beginning of the period		20			56
Funds used for utility property additions and construction expenditures	$	(247	)	$	(269	)
Funds used for nonutility property additions		-			(5	)
Funds used for investments		(14	)		(14	)

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

CAPITAL TRANSACTIONS

In June 2005 $525 million in committed five-year revolving credit facilities for SCE&G and Fuel Company were amended to extend the term of the existing credit facilities by an additional year. The credit facilities now will expire on June 30, 2010. None of these credit facilities require the borrower to make a representation as to “no material adverse change” related to financial condition or material litigation at the time of a borrowing, and none of the facilities contains covenants based on credit ratings under which lenders could refuse to advance funds.

On June 15, 2005 SCE&G retired at maturity $150 million in first mortgage bonds. These bonds bore interest at 7.50%. SCE&G used available cash, together with short-term borrowings, to effect the retirement.

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

CAPITAL PROJECTS

In May 2005 SCE&G substantially completed construction of a back-up dam at Lake Murray in order to comply with new federal safety standards mandated by FERC. Construction of the project and related activities cost approximately $275 million, excluding AFC.

ENVIRONMENTAL MATTERS

In March 2005 the Environmental Protection Agency (EPA) issued a final rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. SCE&G has petitioned the United States Court of Appeals for the District of Columbia Circuit to review CAIR. Several other electric utilities have filed separate petitions. The petitioners seek a change in the method CAIR uses to allocate sulfur dioxide emission allowances to a method the petitioners believe is more equitable. The Company believes that installation of additional air quality controls will be needed to meet the CAIR requirements. Compliance plans and cost to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates.

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In March 2005 the EPA issued a final rule establishing a mercury emissions cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. The Company is reviewing the final rule. Installation of additional air quality controls is likely to be required to comply with the mercury rule’s emission caps. Compliance plans and costs to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates.

For other information on environmental matters, see Note 5B to condensed consolidated financial statements.

OTHER MATTERS

Synthetic Fuel

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

The aggregate investment in these partnerships as of September 30, 2005 is approximately $3.5 million, and through September 30, 2005, they have generated and passed through to SCE&G approximately $168.0 million in such tax credits. As previously described at Net Income, in a January 2005 order, the SCPSC approved SCE&G’s request to apply these synthetic fuel tax credits to offset the construction costs of the Lake Murray Dam project. Under the accounting methodology approved by the SCPSC, construction costs related to the project were recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation is recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

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

Depreciation on the Lake Murray Dam remediation account will be matched to available synthetic fuel tax credits on a quarterly basis until the balance in the dam remediation account is zero or until all of the available synthetic fuel tax credits have been utilized. The synthetic fuel tax credit program expires at the end of 2007.

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

The lower end of the inflation-adjusted benchmark range for 2004 was approximately $51 per barrel, while the upper end of that range was approximately $64. Since the reference price of oil for 2004 was less than $37, all of the synthetic fuel tax credits the Company had recorded and deferred through 2004 were available for use. While the benchmark price range for 2005 has been estimated at between $52 and $65 per barrel, the 2005 reference price will not be known until April 2006. During 2005 and subject to continuing review of the estimated benchmark range and reference price of oil for 2005, the Company intends to continue to record synthetic fuel tax credits as they are generated and to apply those credits quarterly to allow the recording of accelerated depreciation related to the balance in the dam remediation project account. The Company cannot predict what impact, if any, the price of oil may have on the Company’s ability to earn and utilize synthetic fuel tax credits in the future. However, the disruptions in the oil and gas markets in the third quarter of 2005 raise significant uncertainty as to the continued availability of the credits, particularly in 2006 and 2007.

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In order to continue to earn these tax credits in future years, SCANA also must be subject to a regular federal income tax liability in 2005 in an amount at least equal to the credits generated in 2005. This tax liability could be insufficient if the Company’s consolidated taxable income were to be significantly reduced as the result of realizing lower income or large deductions. Under provisions of the recently enacted energy bill, any credits generated in 2006 and 2007 in excess of the Company’s tax liability for such years would be subject to carry back or carry forward provisions. The availability of these synthetic fuel tax credits is also subject to coal availability and other operational risks related to the generating plants.

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

As noted above, the disruptions in the oil and gas markets in the third quarter of 2005 raise significant uncertainty as to the continued availability of the credits, particularly in 2006 and 2007. If it is determined that available credits are not sufficient to fully recover the construction costs of the dam remediation, regulatory action to allow recovery of those remaining costs may be sought. As of September 30, 2005, remaining unrecovered costs, based on management’s recording of accelerated deprecation and related tax benefits on its reasonable assumption that 2005’s credits will not be subjected to the phase-out provisions, were $98.3 million.

QUANTITATIVE AND QUALITATIVEDISCLOSURES ABOUT MARKET RISK

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

Interest rate risk - The table below provides information about long-term debt issued by the Company 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, 2005
Millions of dollars				Expected Maturity Date
							There-		Fair
Liabilities	2005	2006	2007		2008	2009	after	Total	Value
Long-Term Debt:
Fixed Rate ($)	3.7	169.9	39.2		39.2	139.1	1,718.2	2,109.3	2,285.7
Average Interest Rate (%)	7.78	8.51	6.86		6.86	6.33	5.88	6.16	n/a

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

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PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

FINANCIAL SECTION

Public Service Company of North Carolina, Incorporated meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and therefore is filing this form with the reduced disclosure format allowed under General Instruction H(2).

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PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

CONDENSED CONSOLIDATEDBALANCE SHEETS

(Unaudited)

	September 30,			December 31,
Millions of dollars	2005			2004
Assets
Gas Utility Plant	$	988		$	947
Accumulated depreciation		(280	)		(262	)
Acquisition adjustment		210			210
Gas Utility Plant, Net		918			895
Nonutility Property and Investments, Net		27			27
Current Assets:
Cash and cash equivalents		2			2
Restricted cash and temporary investments		1			8
Receivables, net of allowance for uncollectible accounts of $1 and $2		37			128
Receivables-affiliated companies		3			7
Inventories (at average cost):
Stored gas		88			70
Materials and supplies		6			5
Prepayments		8			2
Derivative financial instruments		11			-
Deferred income taxes, net		2			4
Other		-			1
Total Current Assets		158			227
Deferred Debits:
Due from affiliate-pension asset		11			12
Regulatory assets		18			26
Other		3			4
Total Deferred Debits		32			42
Total	$	1,135		$	1,191

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	September 30,		December 31,
Millions of dollars	2005		2004
Capitalization and Liabilities
Capitalization:
Common equity	$	522	$	513
Long-term debt, net		270		274
Total Capitalization		792		787
Current Liabilities:
Short-term borrowings		17		58
Current portion of long-term debt		3		3
Accounts payable		39		66
Accounts payable-affiliated companies		3		8
Customer deposits and customer prepayments		14		14
Taxes accrued		5		4
Interest accrued		4		6
Distributions/dividends declared		4		4
Other		4		11
Total Current Liabilities		93		174
Deferred Credits:
Deferred income taxes, net		107		105
Deferred investment tax credits		1		1
Due to affiliate-postretirement benefits		19		19
Other regulatory liabilities		21		10
Asset retirement obligations		89		84
Other		13		11
Total Deferred Credits		250		230
Commitments and Contingencies (Note 5)		-		-
Total	$	1,135	$	1,191

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

CONDENSED CONSOLIDATEDSTATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30						September 30,
Millions of dollars	2005			2004			2005			2004
Operating Revenues	$	60		$	53		$	390		$	348
Cost of Gas		35			30			261			226
Gross Margin		25			23			129			122
Operating Expenses:
Operation and maintenance		18			18			58			58
Depreciation and amortization		9			9			26			26
Other taxes		2			2			6			6
Total Operating Expenses		29			29			90			90
Operating Income (Loss)		(4	)		(6	)		39			32
Other Income, Including Allowance for Equity Funds    Used During Construction		1			-			3			1
Interest Charges, Net of Allowance for Borrowed Funds    Used During Construction		(5	)		(5	)		(15	)		(15	)
Income (Loss) Before Income Tax Expense (Benefit) and
Earnings from Equity Method Investments		(8	)		(11	)		27			18
Income Tax Expense (Benefit)		(1	)		(4	)		13			8
Income (Loss) Before Earnings from Equity Method Investments		(7	)		(7	)		14			10
Earnings from Equity Method Investments		1			1			3			3
Net Income (Loss)	$	(6	)	$	(6	)	$	17		$	13

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OFCASH FLOWS

(Unaudited)

	Nine Months Ended
	September 30,
Millions of dollars	2005			2004
Cash Flows From Operating Activities:
Net income	$	17		$	13
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization		28			27
Loss on sale of assets		-			1
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		95			86
Inventories		(20	)		(14	)
Regulatory assets		(3	)		1
Regulatory liabilities		1			1
Accounts payable		(38	)		(29	)
Deferred income taxes, net		4			3
Taxes accrued		1			(5	)
Changes in gas adjustment clauses		21			(4	)
Changes in other assets		(15	)		(9	)
Changes in other liabilities		(7	)		(1	)
Net Cash Provided From Operating Activities		84			70
Cash Flows From Investing Activities:
Construction expenditures, net of AFC		(36	)		(34	)
Nonutility and other		5			(1	)
Net Cash Used For Investing Activities		(31	)		(35	)
Cash Flows From Financing Activities:
Short-term borrowings, net		(41	)		(36	)
Net capital contribution from parent		2			-
Retirement of long-term debt		(3	)		(3	)
Distributions/dividends		(11	)		(12	)
Net Cash Used For Financing Activities		(53	)		(51	)
Net Increase (Decrease) In Cash and Cash Equivalents		-			(16	)
Cash and Cash Equivalents, January 1		2			18
Cash and Cash Equivalents, September 30	$	2		$	2
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $1 and $1)	$	16		$	16
- Income taxes	$	24		$	20
Noncash Investing and Financing Activities:
Accrued construction expenditures		2			-

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

NOTESTO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2005

(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 (PSNC Energy, and together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, 2004. These are interim financial statements, and due to the seasonality of the Company’s business, the amounts reported in the Condensed Consolidated Statements of Operations are not necessarily indicative of amounts expected for the full year. In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature, which are necessary for a fair statement of the results for the interim periods reported.

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.  Basis of Accounting

The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS 71 requires cost-based rate-regulated utilities to recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, as of September 30, 2005 the Company has recorded approximately $18 million and $110 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.

	September 30,			December 31,
Millions of dollars	2005			2004
Excess deferred income taxes	$	(1	)	$	(1	)
Under- (over-) collections-gas cost adjustment clause, net		(1	)		9
Unrealized gain-hedging		(11	)		-
Deferred environmental remediation costs		10			8
Asset retirement obligations		(89	)		(84	)
Total	$	(92	)	$	(68	)

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

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

Unrealized gain-hedging represents the change in fair value of derivative financial instruments, including options, used for hedging natural gas purchases.

Deferred environmental remediation costs represent costs associated with the assessment and cleanup of manufactured gas plant (MGP) sites currently or formerly owned by the Company. A portion of the costs incurred has been recovered through rates. Amounts incurred and deferred, net of insurance settlements, that are not currently being recovered through rates are approximately $1.7 million. Management believes that these costs and the estimated remaining costs of approximately $8.7 million will be recoverable.

Asset retirement obligations represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets.

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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.Total Comprehensive Income

Total comprehensive income was not significantly different from net income for any period reported. Accumulated other comprehensive income (loss) of the Company totaled $(0.4) million and $(0.7) million as of September 30, 2005 and December 31, 2004, respectively.

C. New Accounting Matters

SFAS 154,“Accounting Changes and Error Corrections,”was issued in June 2005. It requires retrospective application to financial statements of prior periods for every voluntary change in accounting principle unless such retrospective application is impracticable. SFAS 154 replaces Accounting Principles Board (APB) Opinion 20,“Accounting Changes,” and SFAS 3,“Reporting Accounting Changes in Interim Financial Statements,” although it carries forward some of their provisions. The Company will adopt SFAS 154 in the first quarter of 2006, and does not expect that the initial adoption will have a material impact on the Company’s results of operations, cash flows or financial position.

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

D. Reclassifications

Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2005.

2.       RATE AND OTHER REGULATORY MATTERS

The Company’s rates are established using a benchmark cost of gas approved by the NCUC, which may be modified periodically to reflect changes in the market price of natural gas. The Company revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews the Company’s gas purchasing practices annually.

The Company’s benchmark cost of gas in effect during the period January 1, 2004 through September 30, 2005 was as follows:

Rate Per Therm	Effective Date
$.600	January-September 2004
$.675	October-November 2004
$.825	December 2004-January 2005
$.725	February-July 2005
$.825	August-September 2005

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   In September 2005 the NCUC approved the Company’s request to increase the benchmark cost of gas from $.825 per therm to $1.100 per therm for service rendered on and after October 1, 2005. In October 2005 the NCUC approved the Company’s request to increase the benchmark cost of gas from $1.100 per therm to $1.275 per therm for service rendered on and after November 1, 2005.

   In September 2005 in connection with the Company’s 2005 Annual Prudence Review, the NCUC determined that the Company’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12-month review ended March 31, 2005. The NCUC also authorized new rate decrements, effective October 1, 2005, to refund over-collections of certain gas costs included in deferred accounts.

A state expansion fund, established by the North Carolina General Assembly in 1991 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 September 2005 the NCUC approved the Company’s request for disbursement of up to $1.1 million from the expansion fund to extend natural gas service to Louisburg, North Carolina. The project will be completed in 2006.

In March 2005 the Company refunded approximately $7.7 million in pipeline supplier refunds by a direct bill credit to various customers.

In January 2005 the NCUC authorized the Company to defer for subsequent rate consideration certain expenses incurred to comply with the U. S. Department of Transportation’s Pipeline Integrity Management requirements. This accounting treatment was effective November 1, 2004.

3.         FINANCIAL INSTRUMENTS

The Company utilizes various financial derivatives, including those designated as cash flow hedges related to natural gas. The Company also utilizes swap agreements to manage interest rate risk. These transactions are more fully described in Note 7 to the consolidated financial statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004.

The Company utilizes derivative financial instruments for hedging natural gas purchases. Transaction fees and any realized gains or losses are recorded in deferred accounts for subsequent rate consideration. As of September 30, 2005 the Company had a deferred net realized gain of approximately $3.7 million. In addition, as of September 30, 2005 the Company had unrealized gains of approximately $11 million, also recorded in other regulatory liabilities.

The Company also utilizes a swap agreement to manage interest rate risk. At September 30, 2005 the estimated fair value of the Company’s swap was $0.7 million (gain) related to a notional amount of $22.4 million.

4.          DEBT AND CREDIT FACILITY

 In June 2005 PSNC Energy amended its $125 million committed five-year revolving credit facility to extend the term of the existing facility by an additional year. The facility now will expire on June 30, 2010.

5.         COMMITMENTS AND CONTINGENCIES

The Company is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. The Company’s actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other potentially responsible parties. The Company has recorded a liability and associated regulatory asset of approximately $8.7 million, which reflects its estimated remaining liability at September 30, 2005. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates are approximately $1.7 million. Management believes that all MGP cleanup costs will be recoverable through gas rates.

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6.       SEGMENT OF BUSINESS INFORMATION

Gas Distribution is the Company’s only reportable segment. Gas Distribution uses operating income to measure profitability. Intersegment revenues were not significant. All Other includes equity method investments.

			2005									2004
			Operating			Net						Operating			Net
	External		Income			Income			Segment	External		Income			Income			Segment
(Millions of dollars)	Revenue		(Loss)			(Loss)			Assets	Revenue		(Loss)			(Loss)			Assets
Three Months Ended September 30,
Gas Distribution	$	60	$	(4	)	$	(6	)		$	53	$	(6	)	$	(6	)
All Other		-		n/a			-				-		n/a			-
Adjustments/Eliminations		-		-			-				-		-			-
Consolidated Total	$	60	$	(4	)	$	(6	)		$	53	$	(6	)	$	(6	)

Nine Months Ended September 30,
Gas Distribution	$	390	$	39	$	17	$	1,029	$	348	$	32	$	13	$	994
All Other		-		n/a		-		28		-		n/a		-		27
Adjustments/Eliminations		-		-		-		78		-		-		-		72
Consolidated Total	$	390	$	39	$	17	$	1,135	$	348	$	32	$	13	$	1,093

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PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

MANAGEMENT’S NARRATIVEANALYSIS OF RESULTS OF OPERATIONS

The following discussion should be read in conjunction with Management’s Narrative Analysis of Results of Operations appearing in Public Service Company of North Carolina, Incorporated’s (together with its consolidated subsidiaries, PSNC Energy) Annual Report on Form 10-K for the year ended December 31, 2004.

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

Net Income and Distributions/Dividends

Net income for the nine months ended September 30, 2005 increased $4.0 million compared to the same period in 2004, primarily due to increased margin.

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

PSNC Energy’s Board of Directors has authorized the following distributions/dividends on common stock held by SCANA during 2005:

Declaration Date	Amount	Quarter Ended	Payment Date
February 17, 2005	$3.5 million	March 31, 2005	April 1, 2005
May 5, 2005	$3.5 million	June 30, 2005	July 1, 2005
July 27, 2005	$4.0 million	September 30, 2005	October 1, 2005
November 2, 2005	$4.0 million	December 31, 2005	January 1, 2006

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	2005		% Change			2004
Operating revenues	$	389.8		12.0	%	$	347.9
Less: Gas purchased for resale		260.7		15.3	%		226.1
Margin	$	129.1		6.0	%	$	121.8

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 Gas distribution sales margin increased primarily due to increased residential customer growth and increased consumption.

Other Income

Other income improved primarily due to the recognition of a $1 million loss in 2004 on the sale of PSNC Energy’s former corporate headquarters and due to approximately $0.5 million in increased interest income on amounts under-collected from customers through the Rider D mechanism.

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 2005 construction budget is approximately $58 million, compared to actual construction expenditures through September 30, 2005 of approximately $43 million. PSNC Energy’s ratio of earnings to fixed charges for the 12 months ended September 30, 2005 was 3.23.

At September 30, 2005 PSNC Energy had $17.1 million in outstanding short-term borrowings at a weighted average interest rate of 3.9% and unused lines of credit of $125 million. In addition, in June 2005 PSNC Energy amended a $125 million committed five-year revolving credit facility to extend the term of the existing facility by an additional year. The credit facility now will expire on June 30, 2010. The facility does not require the borrower to make a representation as to “no material adverse change” related to financial condition or material litigation at the time of a borrowing, and the facility does not contain covenants based on credit ratings under which lenders could refuse to advance funds.

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Item 4. Controls and Procedures

As of September 30, 2005 each of SCANA Corporation (SCANA), South Carolina Electric & Gas Company (SCE&G) and Public Service Company of North Carolina, Incorporated (PSNC Energy) conducted separate evaluations under the supervision and with the participation of its management, including its Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of its disclosure controls and procedures. Based on these evaluations, the CEO and CFO in each case concluded that as of September 30, 2005 disclosure controls and procedures related to each company were effective. There has been no change in SCANA’s, SCE&G’s or PSNC Energy’s internal control over financial reporting during the quarter ended September 30, 2005 that has materially affected or is reasonably likely to materially affect SCANA’s, SCE&G’s or PSNC Energy’s internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Each of SCANA Corporation (SCANA), South Carolina Electric & Gas Company (SCE&G) and Public Service Company of North Carolina, Incorporated (PSNC Energy) are engaged in various claims and litigation incidental to their business operations which management anticipates will be resolved without material loss. The status of matters previously disclosed in their respective 2004 Annual Reports on Form 10-K have not changed significantly unless noted below.

Pending Litigation and Claims

A complaint was filed on October 22, 2003 against SCE&G by the State of South Carolina alleging that SCE&G violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality’s limits. The complaint alleged that SCE&G failed to obey, observe or comply with the lawful order of the SCPSC by charging franchise fees to those not residing within a municipality. The complaint sought restitution to all affected customers and penalties up to $5,000 for each separate violation. The State of South Carolina v. SCE&G claim has been settled by an agreement between the parties, and the settlement has been approved by the court. The allegations were also the subject of a purported class action lawsuit filed in December 2003, against Duke Energy Corporation, Progress Energy Services Company and SCE&G (styled as Edwards v. SCE&G), but that case has been dismissed by the plaintiff. In addition, SCE&G filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to SCE&G’s electric and gas service, to approve SCE&G’s efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation that the SCPSC deems just and proper to regulate the franchise fee collection process. A hearing on this petition has not been scheduled. The Company believes that the resolution of these matters will not have a material adverse impact on its results of operations, cash flows or financial condition.

In 1999 an unsuccessful bidder for the purchase of certain propane gas assets of the subsidiaries of SCANA filed suit against SCANA in Circuit Court, seeking unspecified damages. The suit alleged the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. On October 21, 2004, the jury issued an adverse verdict on this matter against SCANA for four causes of action for damages totaling $48 million.

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

Post-verdict motions were heard in November 2004 and January 2005. In April 2005, post-trial motions were decided by the Court, and the plaintiff was ordered to elect a single remedy from the multiple jury awards. In response to the April 2005 election order, the plaintiff elected a remedy with damages totaling $18 million, and the Company placed the funds in escrow with the Clerk of Court to forestall the accrual of post-judgment interest. SCANA believes its accrued liability is still a reasonable estimate. However, SCANA continues to believe that the verdict was inconsistent with the facts presented and applicable laws. Both parties have appealed the judgment.

The Company is also defending a claim for $2.7 million for reimbursement of legal fees and expenses under an indemnification and hold harmless agreement in the contract for the sale of the propane gas assets. A bench trial on the indemnification was held on January 14, 2005, and on August 9, 2005 an order was entered against the Company in the amount of $2.6 million. The Company filed a motion and amended motion to vacate or in the alternative to alter or amend or reconsider the order and is currently awaiting a decision. The Company has made provision for this potential loss and further believes that the resolution of this claim will not have a material adverse impact on its results of operations, cash flows or financial condition.

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 SCE&G has been named, along with 27 others, by the Environmental Protection Agency (EPA) as a potentially responsible party (PRP) at the Carolina Transformer Superfund site located in Fayetteville, NC.  The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from 1967 to 1984.  During that time, SCE&G occasionally used CTC for the repair of existing transformers and the purchase of new transformers.  In 1984, EPA initiated a cleanup of PCB-contaminated soil and groundwater at the site.  EPA reports that it has spent $36 million to date.  SCE&G’s records indicated that only minimal quantities of used transformers were shipped to CTC, and it is not clear if any contained PCB-contaminated oil.  Although a basis for the allocation of clean-up costs among the 28 PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition.

Rate Matter

In October 2005, the SCPSC granted SCE&G an overall increase of $22.9 million, or 5.69 percent, in retail gas base rates. The new rates are based on an allowed return on common equity of 10.25 percent, and became effective with the first billing cycle in November 2005.

Item 5. Other Information

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

The following disclosure would otherwise have been filed on Form 8-K under the heading “Item 1.01. Entry into a Material Definitive Agreement.”

On November 2, 2005 the SCANA Corporation Director Compensation and Deferral Plan was amended to increase the percentage of the retainer fee paid to nonemployee directors in shares of SCANA common stock from 60 percent to 100 percent.  See Exhibit 10.03a for the text of the amendment.

Item 6. Exhibits

 SCANA Corporation (SCANA), South Carolina Electric & Gas Company (SCE&G) and Public Service Company of North Carolina, Incorporated (PSNC Energy):

 Exhibits filed or furnished with this Quarterly Report on Form 10-Q are listed in the following Exhibit Index.

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

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SIGNATURES

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

SCANA CORPORATION

SOUTH CAROLINA ELECTRIC & GAS COMPANY

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

(Registrants)

By:	/s/James E. Swan, IV
November 4, 2005	James E. Swan, IV
	Controller
	(Principal accounting officer)

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EXHIBIT INDEX

	Applicable to Form 10-Q of
Exhibit			PSNC
No.	SCANA	SCE&G	Energy	Description

3.11		X		Articles of Amendment dated March 9, 2005 amending the Restated Articles of Incorporation of South Carolina Electric & Gas Company (Filed as Exhibit 3.11 to Form 10-Q for the quarter ended March 31, 2005)
3.12		X		Articles of Amendment dated May 16, 2005 amending the Restated Articles of Incorporation of South Carolina Electric & Gas Company (Filed as Exhibit 3.12 to Form 10-Q for the quarter ended June 30, 2005)
3.13		X		Articles of Amendment dated June 15, 2005 amending the Restated Articles of Incorporation of South Carolina Electric & Gas Company (Filed as Exhibit 3.13 to Form 10-Q for the quarter ended June 30, 2005)
3.14		X		Articles of Amendment dated August 16, 2005 amending the Restated Articles of Incorporation of South Carolina Electric & Gas Company (Filed herewith)
4.12			X	Amended and Restated Five-Year Credit Agreement dated June 30, 2005 (Filed as Exhibit 4.12 to Form 10-Q for the quarter ended June 30, 2005)
10.03a	X			Amendment to SCANA Director Compensation and Deferral Plan adopted November 2, 2005 (Filed herewith)
10.10	X			SCANA Corporation Short-Term Annual Incentive Plan as amended and restated effective January 1, 2005 (Filed herewith)
31.01	X			Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.02	X			Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
31.03		X		Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.04		X		Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
31.05			X	Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.06			X	Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
32.01	X			Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.02	X			Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.03		X		Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.04		X		Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.05			X	Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.06			X	Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

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