UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THES~~ECURITIES~~ SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~September 30, 2005~~March 31, 2006

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 a large accelerated filer, an accelerated filer, ~~(as defined~~or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange ~~Act Rule 12b-2)~~Act). ~~SCANA Corporation Yes~~ x Noo ~~South Carolina Electric & Gas Company Yes~~ o No x ~~Public Service Company of North Carolina, Incorporated Yes~~o Nox

SCANA Corporation	Large accelerated filer x	Accelerated filer ¨	Non-accelerated filer ¨
South Carolina Electric & Gas Company	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x
Public Service Company of North Carolina, Incorporated	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x

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¨ Nox 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	Description of Common Stock	Shares Outstanding at ~~October 31, 2005~~April 30, 2006
SCANA Corporation	Without Par Value	~~114,483,432~~115,482,404
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~~MARCH 31, 2006

PART I. FINANCIAL INFORMATION			Page

SCANA Corporation Financial Section			3
	Item 1.	Financial Statements
		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
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	25


~~SCANA Corporation~~South Carolina Electric & Gas Company Financial Section					327
	~~Condensed Consolidated Balance Sheets~~ Item 1.			4Financial Statements
				Condensed Consolidated Balance Sheets	28
				Condensed Consolidated Statements of Income	630
				Condensed Consolidated Statements of Cash Flows	731
	~~Condensed Consolidated Statements of Comprehensive Income~~			8
	Notes to Condensed Consolidated Financial Statements	932
	Item 2.			Management’s Discussion and Analysis of Financial Condition and Results of Operations	2041
	Item 3.			Quantitative and Qualitative Disclosures About Market Risk	30 46

~~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		5547
	Item 1.			Financial Statements
				Condensed Consolidated Balance Sheets	5648
				Condensed Consolidated Statements of ~~Operations~~Income	5850
				Condensed Consolidated Statements of Cash Flows	5951
				Notes to Condensed Consolidated Financial Statements	6052
	Item 2.			Management’s Narrative Analysis of Results of Operations	6456

Item 4.			Controls and Procedures		6658

PART II. OTHER INFORMATION					59

~~PART II. OTHER INFORMATION~~			67

Item 1.	Legal Proceedings		6759

Item 5. 6.			~~Other Information~~Exhibits		6859

~~Item 6.~~ Signatures					~~Exhibits~~	6860

~~Signatures~~					69

Exhibit Index		7061

~~Table of Contents~~

SCANACORPORATION

FINANCIAL SECTION

~~Table of Contents~~

~~PART I. FINANCIAL INFORMATION~~

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

~~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

~~Table of Contents~~

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.~~

~~Table of Contents~~

SCANA CORPORATION

CONDENSED CONSOLIDATED~~STATEMENTS OF INCOME~~ BALANCE SHEETS

(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.


	March 31,			December 31,
Millions of dollars	2006			2005
Assets
Utility Plant In Service	$	9,059		$	8,999
Accumulated Depreciation and Amortization		(2,680	)		(2,688	)
		6,379			6,311
Construction Work in Progress		191			175
Nuclear Fuel, Net of Accumulated Amortization		26			28
Acquisition Adjustments		230			230
Utility Plant, Net		6,826			6,744

Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $66 and $62		114			108
Assets held in trust, net - nuclear decommissioning		53			52
Other investments		88			87
Nonutility Property and Investments, Net		255			247

Current Assets:
Cash and cash equivalents		109			62
Receivables, net of allowance for uncollectible accounts of $26 and $25		643			881
Receivables - affiliated companies		27			24
Inventories (at average cost):
Fuel		233			284
Materials and supplies		84			79
Emission allowances		53			54
Prepayments and other		51			54
Deferred income taxes		28			26
Total Current Assets		1,228			1,464

Deferred Debits and Other Assets:
Environmental		28			28
Pension asset, net		306			303
Other regulatory assets		571			589
Other		146			154
Total Deferred Debits and Other Assets		1,051			1,074
Total	$	9,360		$	9,529

	March 31,		December 31,
Millions of dollars	2006		2005
Capitalization and Liabilities
Shareholders’ Investment:
Common equity	$	2,746	$	2,677
Preferred stock (Not subject to purchase or sinking funds)		106		106
Total Shareholders’ Investment		2,852		2,783
Preferred Stock, net (Subject to purchase or sinking funds)		8		8
Long-Term Debt, net		2,916		2,948
Total Capitalization		5,776		5,739

Current Liabilities:
Short-term borrowings		389		427
Current portion of long-term debt		213		188
Accounts payable		273		471
Accounts payable - affiliated companies		28		26
Customer deposits and customer prepayments		67		70
Taxes accrued		57		112
Interest accrued		49		52
Dividends declared		51		47
Other		83		107
Total Current Liabilities		1,210		1,500

Deferred Credits and Other Liabilities:
Deferred income taxes, net		952		940
Deferred investment tax credits		121		121
Asset retirement obligations		327		322
Other asset removal costs		561		498
Postretirement benefits		150		148
Other regulatory liabilities		134		117
Other		129		144
Total Deferred Credits and Other Liabilities		2,374		2,290

Commitments and Contingencies (Note 4)		-		-
Total	$	9,360	$	9,529

See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended
	March 31,
Millions of dollars, except per share amounts	2006			2005

Operating Revenues:
Electric	$	399		$	415
Gas - regulated		514			460
Gas - nonregulated		476			391
Total Operating Revenues		1,389			1,266

Operating Expenses:
Fuel used in electric generation		117			128
Purchased power		4			7
Gas purchased for resale		811			661
Other operation and maintenance		157			158
Depreciation and amortization		76			245
Other taxes		39			39
Total Operating Expenses		1,204			1,238

Operating Income		185			28

Other Income (Expense):
Other revenues		57			55
Other expenses		(45	)		(45	)
Allowance for equity funds used during construction		-			3
Interest charges, net of allowance for borrowed funds
used during construction of $1 and $1		(54	)		(54	)
Preferred dividends of subsidiary		(2	)		(2	)
Total Other Expense		(44	)		(43	)

Income (Loss) Before Income Tax Expense (Benefit), Losses from Equity
Method Investments and Cumulative Effect of Accounting Change		141			(15	)

Income Tax Expense (Benefit)		45			(179	)

Income Before Losses from Equity Method
Investments and Cumulative Effect of Accounting Change		96			164
Losses from Equity Method Investments		(4	)		(63	)
Cumulative Effect of Accounting Change, net of taxes		6			-

Net Income	$	98		$	101

Basic and Diluted Earnings Per Share of Common Stock:
Before Cumulative Effect of Accounting Change	$	.80		$	.89
Cumulative Effect of Accounting Change, net of taxes		.05			-
Basic and Diluted Earnings Per Share	$	.85		$	.89
Weighted Average Shares Outstanding (millions)		115.0			112.9

See Notes to Condensed Consolidated Financial Statements.

~~Table of Contents~~

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OFCASH FLOWS

(Unaudited)

	Nine Months Ended						Three Months Ended
	September 30,						March 31,
Millions of dollars	2005			2004			2006			2005
Cash Flows From Operating Activities:
Net income	$	246		$	215		$	98		$	101
Adjustments to reconcile net income to net cash provided from operating activities:
Losses (earnings) from equity method investments		68			(1	)
Cumulative effect of accounting change, net of taxes								(6	)		-
Losses from equity method investments								4			63
Depreciation and amortization		425			207			78			246
Amortization of nuclear fuel		4			16			5			6
Gain on sale of assets and investments		(8	)		-
Hedging activities		12			1			-			8
Impairment of investments		-			25
Allowance for equity funds used during construction		(1	)		(13	)
Carrying cost recovery		(8	)		-			(2	)		(3	)
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		137			124			235			30
Inventories		(125	)		(75	)		34			45
Prepayments and other		(2	)		(20	)		5			15
Pension asset		(13	)		(10	)		(3	)		(4	)
Other regulatory assets		31			(24	)		7			(18	)
Deferred income taxes, net		22			80			8			(37	)
Regulatory liabilities		(156	)		30			14			(131	)
Postretirement benefits obligations		4			5
Postretirement benefits								2			2
Accounts payable		(39	)		(94	)		(187	)		(76	)
Taxes accrued		(48)			(17	)		(55	)		(64	)
Interest accrued		(2	)		1			(3	)		5
Changes in fuel adjustment clauses		(36	)		23			16			30
Changes in other assets		12			2			6			4
Changes in other liabilities		18			15			(37	)		(35	)
Net Cash Provided From Operating Activities		541			490			219			187
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(285	)		(311	)		(83	)		(121	)
Proceeds from sale of assets and investments		8			2
Nonutility property additions		(11	)		(15	)		(10	)		(3	)
Investments in affiliates and other		(26	)		(14	)
Investments								(10	)		(4	)
Net Cash Used For Investing Activities		(314	)		(338	)		(103	)		(128	)
Cash Flows From Financing Activities:
Proceeds from issuance of debt		197			124			-			197
Proceeds from issuance of common stock		66			47			21			25
Repayment of debt		(459	)		(109	)		(6	)		(2	)
Repurchase of common stock		-			(4	)
Redemption of preferred stock		(1	)		-
Dividends on equity securities		(134	)		(125	)		(46	)		(43	)
Short-term borrowings, net		156			(11	)		(38	)		(26	)
Net Cash Used For Financing Activities		(175	)		(78	)
Net Cash Provided From (Used For) Financing Activities								(69	)		151
Net Increase In Cash and Cash Equivalents		52			74			47			210
Cash and Cash Equivalents, January 1		119			117			62			119
Cash and Cash Equivalents, September 30	$	171		$	191
Cash and Cash Equivalents, March 31							$	109		$	329
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $2 and $8)	$	163		$	151
Cash paid for - Interest (net of capitalized interest of $1 and $1)							$	57		$	50
- Income taxes		45			21			3			30

Noncash Investing and Financing Activities:
Unrealized loss on securities available for sale, net of tax		-			(1	)
Accrued construction expenditures		14			22			23			16

See Notes to Condensed Consolidated Financial Statements.

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.

~~Table of Contents~~


SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,
Millions of dollars	2006		2005

Net Income	$	98	$	101

Other Comprehensive Income, net of tax:
Unrealized gains on hedging activities		2		7
Total Comprehensive Income ⁽¹⁾	$	100	$	108

⁽¹⁾ Accumulated other comprehensive income totaled $5.7 million as of March 31, 2006 and $4.2 million as of
December 31, 2005.


See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~September 30, 2005~~March 31, 2006

(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.~~2005. These are interim financial statements, and due to the seasonality of the Company’s business and matters that may occur during the rest of the year, 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~~the regulatory assets and regulatory liabilities summarized as 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 )

	March 31,		December 31,
Millions of dollars	2006		2005
Regulatory Assets:
Accumulated deferred income taxes	$	177	$	177
Under-collections - electric fuel and gas cost adjustment clauses		44		61
Deferred purchased power costs		15		17
Deferred environmental remediation costs		28		28
Asset retirement obligations and related funding		255		250
Franchise agreements		55		56
Deferred regional transmission organization costs		10		11
Other		15		17
Total Regulatory Assets	$	599	$	617

Regulatory Liabilities:
Accumulated deferred income taxes	$	39	$	39
Over-collections - electric fuel and gas cost adjustment clauses		24		20
Other asset removal costs		561		498
Storm damage reserve		40		38
Planned major maintenance		14		9
Other		17		11
Total Regulatory Liabilities	$	695	$	615

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~~represent 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~~a three-year period 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~~$17.5 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~~$2.9 million. Management believes that these costs and the estimated remaining costs of ~~approximately $8.7~~$7.4 million will be recoverable by PSNC Energy.

Asset retirement ~~obligation (ARO) - nuclear decommissioning~~obligations (AROs) and related funding ~~represents~~represent the regulatory asset associated with the legal obligation to decommission and dismantle V. C. Summer Nuclear Station (Summer Station) and conditional AROs recorded as required by SFAS 143,“Accounting for Asset Retirement Obligations,” and Financial Accounting Standards Board Interpretation (FIN) 47, “Accounting for Conditional 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.

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

The storm damage reserve represents an SCPSC approved reserve account for SCE&G capped at $50 million to be collected through rates. The accumulated storm damage reserve can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. For the three months ended March 31, 2006, no amounts were drawn from this reserve account.

Planned major maintenance related to certain fossil and hydro-turbine equipment and nuclear refueling outages is accrued in advance of the time the costs are incurred. SCE&G is allowed to collect $8.5 million annually over an eight-year period through electric rates to offset turbine maintenance expenditures. Nuclear refueling charges are accrued during each 18-month refueling outage cycle based on an SCPSC accounting order. Nuclear refueling charges do not receive special rate consideration.

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~~Share-Based Compensation ~~Plan~~

~~Under the~~The SCANA Corporation Long-Term Equity Compensation Plan ~~(the Plan), certain employees and non-employee directors may receive~~provides for grants of incentive and nonqualified stock options, stock appreciation rights, restricted stock, performance shares and ~~other forms~~performance units to certain key employees and non-employee directors. The plan currently authorizes the issuance of ~~equity compensation. The Company accounts~~up to five million shares of the Company’s common stock, no more than one million of which may be granted in the form of restricted stock.

SFAS 123 (revised 2004),“Share-Based Payment,” (SFAS 123(R)) requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for ~~this equity-based compensation using~~ the ~~intrinsic value method under~~award. SFAS 123(R) replaces SFAS 123, “Accounting for Stock-Based Compensation” and supersedes APB 25,“Accounting for Stock Issued to ~~Employees,~~Employees.” The cumulative effect of the adoption of SFAS 123(R) on January 1, 2006 resulted in a $.05 per share (net of tax) gain in the first quarter of 2006 based on a reduction of prior compensation accruals for performance awards (discussed below) granted in 2004 and ~~related interpretations.~~2005.

Liability Awards

Certain executives are granted a target number of performance shares on an annual basis that vest over a three-year period. Each performance share has a value that is equal to, and changes with, the value of a share of SCANA common stock, and dividend equivalents are accrued on, and reinvested in, the performance shares. Payout of performance share awards is determined by SCANA's performance against pre-determined measures of total shareholder return (TSR) as compared to a peer group of utilities (weighted 60%) and growth in earnings per share (weighted 40%) over the three-year plan cycle. TSR is calculated by dividing stock price increase over the three-year period, plus cash dividends, by the stock price as of the beginning of the period. Payouts vary according to SCANA's ranking against the peer group and relative earnings per share projection achievement. Awards are designated as target shares of SCANA common stock and may be paid in stock or cash or a combination of stock and cash at SCANA's discretion.

Under SFAS 123(R), compensation cost of these liability awards is recognized over the three-year performance period based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Cash-settled liabilities totaling $6.4 million were paid during the three months ended March 31, 2006. No such payments were made during the corresponding period in 2005.

Compensation expense recognized in the Statements of Income for performance awards, exclusive of the cumulative effect adjustment discussed previously, totaled $1.3 million and $1.9 million for the three months ended March 31, 2006 and 2005, respectively. In addition, the Company ~~has adopted~~capitalized compensation cost of $0.1 million and $0.2 million during the ~~disclosure provisions of SFAS 123,~~~~“Accounting for Stock-Based Compensation”~~three months ended March 31, 2006 and ~~SFAS 148,~~~~“Accounting for Stock-Based Compensation-Transition and Disclosure.”~~2005, respectively.

~~Options, all~~Equity Awards

A summary of ~~which were~~activity related to nonqualified stock options since December 31, 2005 follows:

	Number of Options	Weighted Average Exercise Price
Outstanding-December 31, 2005	439,270	$27.53
Exercised	(11,341)	27.09
Outstanding-March 31, 2006	427,929	27.54

No stock options have been granted ~~prior to 2003,~~since August 2002, and all ~~of which were~~outstanding options have been fully vested assince August 2005. The options expire ten years after the grant date. At March 31, 2006, all outstanding options were currently exercisable at prices ranging from $25.50-$29.60, and had a weighted-average remaining contractual life of ~~September 30, 2005,~~5.6 years.

All options 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~~was 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,~~123(R), pro forma net income and earnings per share for the three months ended March 31, 2005 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	$	100.8
Net income - pro forma (millions)	$	100	$	54	$	246	$	214		100.7
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
Basic and diluted earnings per share - as reported and pro forma											.89

The exercise of stock options during the period was satisfied using original issue shares of the Company’s common stock. The Company realized $0.3 million and $5.1 million upon the exercise of options in the quarters ended March 31, 2006 and 2005, respectively. In addition, tax benefits resulting from the exercise of those stock options totaling $0.1 million and $0.8 million were credited to additional paid in capital in those quarters.

~~Table of Contents~~

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*
											Pension Benefits						Other Postretirement Benefits
Millions of dollars											2006			2005			2006		2005
*Three months ended March 31,*
Service cost	$	9.2		$	8.3		$	2.7	$	2.4	$	3.5		$	3.0		$	1.2	$	0.9
Interest cost		28.7			28.1			8.0		8.7		9.9			9.5			2.8		2.8
Expected return on assets		(57.2	)		(53.2	)		-		-		(18.8	)		(19.1	)		-		-
Prior service cost amortization		5.2			4.9			0.6		1.0		1.7			1.7			0.2		0.3
Transition obligation amortization		0.6			0.6			0.6		0.6		0.1			0.2			0.2		0.2
Amortization of actuarial loss		-			-			0.9		1.5		0.2			-			0.3		0.4
Net periodic benefit (income) cost	$	(13.5	)	$	(11.3	)	$	12.8	$	14.2	$	(3.4	)	$	(4.7	)	$	4.7	$	4.6

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~~&G’s receivables from these affiliated companies ~~approximately $23.5~~were $27.1 million and ~~$18.6~~$24.6 million at ~~September 30, 2005~~March 31, 2006 and December 31, ~~2004,~~2005, respectively. SCE~~&G had recorded as~~&G’s payables to these affiliated companies ~~approximately $23.3~~were $28.0 million and ~~$17.8~~$25.3 million at ~~September 30, 2005~~March 31, 2006 and December 31, ~~2004,~~2005, respectively. SCE&G purchased ~~approximately $70.2~~$64.8 million and ~~$52.7~~$50.9 million of synthetic fuel from these affiliated companies for the three months ended ~~September 30,~~March 31, 2006 and 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~~adopted SFAS 154 in the first quarter of ~~2006, and does not expect that the initial adoption will have a~~2006. There was no material impact on the Company’s results of operations, cash flows or financial position.

~~Table of Contents~~

~~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,”~~123(R) was issued in December 2004 and ~~will require~~requires 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~~is measured based on the grant-date fair value of the instruments ~~issued. Compensation cost will be~~issued and is 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~~ The Company adopted SFAS 123(R) ~~until~~in the first ~~interim or annual reporting period~~quarter of ~~the first fiscal year beginning on or after June 15, 2005, although earlier adoption is allowed.~~2006. The ~~Company does not expect that the initial adoption of SFAS 123(R) will have a material~~ impact on the Company’s results of operations ~~cash flows or financial position.~~is discussed at Note 1B.

G. Reclassifications

Certain amounts from prior periods have been reclassified to conform with the presentation adopted for ~~2005.~~2006.

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.

~~Table of Contents~~

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~~2005 through ~~September 30, 2005~~March 31, 2006 was as follows:

Rate Per KWh	Effective Date
$~~.01678~~	~~January-April 2004~~
~~$.01821~~	~~May-December 2004~~
$.01764	January-April 2005
$.02256	~~May-September 2005~~May 2005-March 2006

On April 11, 2006, as part of the annual review of fuel costs, the SCPSC approved SCE&G’s request to increase the cost of fuel component from $.02256 per KWh to $.02516 per KWh effective the first billing cycle in May 2006. In connection with the increase, SCE&G agreed to spread the recovery of previously under-collected fuel costs of $38.5 million over a two-year period.

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~~were as follows (rate per therm):

Effective Date	Residential	Small/Medium	Large
January-October 2005	$.903	$.903	$.903
November 2005	1.297	1.222	1.198
December 2005	1.362	1.286	1.263
January 2006	1.297	1.222	1.198
February-March 2006	1.227	1.152	1.128

Prior to November 2005, the SCPSC allowed SCE&G to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former MGPs. Effective with the first billing cycle of November 2005, the billing surcharge was eliminated. In its place, SCE&G defers certain MGP environmental costs 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~~regulatory asset accounts and collects and amortizes these costs ~~until November 2006.~~through base rates.

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~~2005 through ~~September 30, 2005~~March 31, 2006 was as follows:

Rate Per Therm	Effective Date
$~~.600~~	~~January-September 2004~~
~~$.675~~	~~October-November 2004~~
$.825	~~December 2004-January~~January 2005
$.725	February-July 2005
$.825	August-September 2005
$1.100	October 2005
$1.275	November-December 2005
$1.075	January 2006
$0.875	February 2006
$0.825	March 2006

~~In September 2005~~On April 3, 2006, PSNC Energy filed an application with the NCUC ~~approved~~requesting a 4.9 percent, or $28.4 million, increase in its base rates. PSNC ~~Energy’s request to increase~~Energy also requested a $7.5 million reduction in the ~~benchmark~~fixed-cost portion of its cost of gas, ~~from $.825 per therm to $1.100 per therm~~resulting in an overall increase of 3.6 percent, or $20.9 million, in rates and charges for ~~service rendered on~~natural gas utility service. The rate increase is largely associated with recovering increased plant investment and ~~after October 1, 2005. In October 2005~~operating costs. If approved, the ~~NCUC approved PSNC Energy’s request to increase~~new rates will be effective for the ~~benchmark cost of gas from $1.100 per therm to $1.275 per therm~~2006-2007 winter season. A hearing is scheduled 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.

~~Table of Contents~~August 2006.

~~A state expansion fund, established by the North Carolina General Assembly in 1991 and funded by refunds~~Refunds from PSNC Energy’s interstate pipeline transporters ~~provides~~are placed in a state-approved expansion fund and provide 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.

~~Table of Contents~~

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.~~2005.

The Company recognizes gains ~~(losses)~~and 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~~loss of ~~$2.4~~$13.0 million and a loss of ~~$(0.4)~~$3.0 million for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2006 and 2005, ~~respectively, and recognized gains of $0.3 million and $3.3 million, respectively, for the corresponding periods ended September 30, 2004.~~respectively. The Company estimates that ~~most of~~ the ~~September 30, 2005~~March 31, 2006 unrealized ~~gain~~loss balance of ~~$8.2~~$4.2 million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in ~~2005 and~~ 2006 as ~~a decrease~~an increase to gas cost if market prices remain at current levels. As of ~~September 30, 2005,~~March 31, 2006, all of the Company's cash flow hedges settle by their terms before the end of December 2007.

At ~~September 30, 2005~~March 31, 2006 the estimated fair value of the Company’s swaps totaled ~~$0.3~~$0.4 million ~~(gain)~~(loss) related to combined notional amounts of $47.4 million.

6.4. 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.~~2005. Commitments and contingencies at ~~September 30, 2005~~March 31, 2006 include the following:

A. Nuclear Insurance

The Price-Anderson Indemnification Act ~~(the Act)~~ deals with public liability for a nuclear ~~incident. The Act~~incident and 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~~Santee Cooper, a 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~~$15.6 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.~~incident. 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

South Carolina Electric & Gas Company

On January 28, 2004, SCE&G and Santee Cooper filed suit in the Court of Federal Claims against the Department of Energy (DOE) for breach of contract. The contract, entered into in 1983, known as the Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (Standard Contract) required the federal government to accept and dispose of spent nuclear fuel and high-level radioactive waste beginning not later than January 31, 1998, in exchange for agreed payments fixed in the Standard Contract at particular amounts. As of the date of filing, the federal government has accepted no spent fuel from Summer Station or any other utility for transport and disposal, and has indicated that it does not anticipate doing so until 2010, at the earliest. As a consequence of the federal government’s breach of contract, the plaintiffs have incurred and will continue to incur substantial costs. On January 9, 2006, SCE&G and Santee Cooper accepted a settlement from DOE which required the payment by DOE of $9 million to the plaintiffs. The payment reimbursed the plaintiffs for certain costs incurred from January 31, 1998 through July 31, 2005. The settlement also provides for the plaintiffs to submit an annual application to DOE for the reimbursement of certain costs incurred subsequent to July 31, 2005. SCE&G received the settlement in March 2006, and recorded its $6 million portion of the settlement as a reduction to the under-collections-electric fuel adjustment clause.

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. The Company is reviewing the final rule. 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.

~~Table of Contents~~

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~~may 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~~may be material and are expected to be recoverable through rates.

SCE&G has been named, along with 27 others, by the EPA as a potentially responsible party (PRP) at the Carolina Transformer Superfund site located in Fayetteville, North Carolina. 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 indicate 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. Any cost arising from this matter is expected to be recoverable through rates.

SCE&G has been named, along with 53 others, by the EPA as a PRP at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia. The EPA placed the site on the National Priorities List on April 19, 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned. While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels. During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils. EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The site has not been cleaned up nor has a cleanup cost been estimated. Although a basis for the allocation of clean-up costs among the 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 impact on its results of operations, cash flows or financial condition. Any cost arising from this matter is 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~~$17.5 million at ~~September 30, 2005.~~March 31, 2006. 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 remediation for contamination at the ~~remaining remediation activities~~site will be completed by mid-2006, with certain monitoring and retreatment activities continuing until 2011. As of ~~September 30, 2005,~~March 31, 2006, SCE&G had spent ~~approximately $21.0~~$21.6 million to remediate the ~~Calhoun Park~~ site and expects to spend an additional ~~$0.8 million.~~$0.3 million prior to entering a monitoring and reporting stage. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of ~~approximately $9~~$9.1 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 inby 2010. As of ~~September 30, 2005,~~March 31, 2006, SCE&G had spent ~~approximately $4.3~~$4.5 million related to these three sites, and expects to spend an additional ~~$8.2~~$11.5 million. Any cost arising from this matter is expected to be recoverable through rates.

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~~PSNC Energy is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. ~~The Company’s actual~~PSNC Energy’s 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~~PRPs. PSNC Energy has recorded a liability and associated regulatory asset of ~~approximately $8.7~~$7.4 million, which reflects its estimated remaining liability at ~~September 30, 2005.~~March 31, 2006. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through ~~gas~~ rates are ~~approximately $1.7~~$2.9 million. ~~Management believes that all MGP cleanup costs will~~Any cost arising from this matter is expected to be recoverable through ~~gas~~ rates.

~~Table of Contents~~

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 In accordance with generally accepted accounting principles, in the third quarter of 2004 ~~the Company~~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~~SCANA 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~~sheet. SCANA believes its accrued liability is ~~still~~ a reasonable estimate. However, ~~the Company~~SCANA continues to believe that the verdict was inconsistent with the facts presented and applicable laws. Both parties have appealed the judgment.

~~The Company~~SCANA 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~~SCANA in the amount of $2.6 million. ~~The Company filed a motion~~On December 2, 2005, the judge vacated this award, and ~~amended motion~~further motions to ~~vacate or in the alternative to alter or amend or reconsider the~~review his order ~~and is currently awaiting a decision. The Company~~are pending. SCANA 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~~nonutility 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~~It is anticipated that this case may go to trial in 2006. SCANA & SCE&G are confident of the propriety of SCE&G’s actions and ~~intends~~intend to mount a vigorous defense. ~~The Company~~SCANA and SCE&G further ~~believes~~believe that the resolution of these claims will not have a material adverse impact on ~~its~~their 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).~~Circuit. The plaintiff alleges the Company made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than the Company’s electricity-related internal communications. The plaintiff 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~~court granted the Company’s motion to dismiss and issued an order dismissing the case on June 29, 2005. The plaintiff has ~~appealed.~~appealed and the plaintiff’s appeal will likely be heard in May. 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.

~~Table of Contents~~

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 South Carolina’s Circuit Court of Common Pleas for 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.Fifth Judicial Circuit. 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~~

D. Other Contingency

In 2004 and early 2005, SCANA and certain of its affiliates, like other integrated utilities, were the subject of an investigation by FERC’s Office of Market Oversight and Investigations (OMOI) focusing, among other things, on the relationship between SCE&G’s merchant and transmission functions. These relationships are among those addressed in FERC Order 2004, a primary purpose of which order is to ensure that affiliates of transmission providers have no marketplace advantage over non-affiliated market participants. In connection with that investigation, SCE&G was assessed no monetary damages or penalties; however, under terms of a Settlement and Consent Agreement entered into on April 1, 2005, and approved by FERC order dated April 27, 2005, SCE&G agreed to the implementation of a compliance plan which includes periodic reports to OMOI.

On January 2, 2006, SCE&G provided to FERC a quarterly update on this compliance plan, which included an acknowledgment of SCE&G’s discovery that it may have improperly utilized network transmission services, rather than point-to-point transmission services, for purchases and sales of electricity in violation of SCE&G’s open access transmission tariff and applicable orders under the Federal Power Act that prohibit the use of network transmission service in support of certain “off-system” sales. This acknowledgement was in part the result of SCE&G’s preliminary review of a FERC order issued following its examination of another energy provider in September 2005. Upon further review of that order and a comprehensive analysis, SCE&G determined and notified FERC that it did improperly utilize network transmission service in a significant number of purchase and sale transactions.

In response to this discovery, SCE&G notified FERC and ceased participation in such transactions, instituted additional self-restrictive procedures as safeguards to ensure full compliance in this area in the future, committed to certain modifications to its compliance plan, including increased levels of training and monitoring, and is fully cooperating with OMOI to resolve this matter.

In the fourth quarter of 2005, SCE&G recorded a loss accrual in the amount of $0.8 million based on its estimation of net revenues from these transactions that occurred after the date of the Settlement and Consent Agreement and that might be deemed to be in violation of FERC's rule on the use of network transmission service and be subject to disgorgement pursuant to FERC orders. SCE&G believes this accrual is a reasonable estimate; however, there remains uncertainty as to what actions may be taken by FERC. Potential actions could include further modifications to the compliance plan or other non-monetary remedies. In addition to the disgorgement of profits, such remedies could also include penalties of up to a maximum of $1 million per violation or per day since August 8, 2005, the effective date of the Energy Policy Act of 2005. In light of SCE&G's self-reporting and other cooperation in the investigation of this matter, SCE&G's belief that no market participants or customers of SCE&G were harmed or disadvantaged by the transactions, and SCE&G’s institution of appropriate safeguards referred to above, SCE&G does not believe that such sanctions are warranted. Nonetheless, SCE&G cannot predict what, if any, actions FERC will take with respect to this matter, and is unable to determine if the resolution of this matter will have a material adverse impact on its operations, cash flows or financial condition.

5.	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

	External			Intersegment			Operating		Net			Segment
Millions of dollars	Revenue			Revenue			Income (Loss)		Income (Loss)			Assets
*Three Months Ended March 31, 2006*
Electric Operations	$	399		$	1		$	91		n/a		$	5,408
Gas Distribution		446			-			60		n/a			1,688
Gas Transmission		68			153			8		n/a			335
Retail Gas Marketing		271			-			n/a	$	21			224
Energy Marketing		205			11			n/a		-			69
All Other		15			75			n/a		(3	)		532
Adjustments/Eliminations		(15	)		(240	)		26		80			1,104
Consolidated Total	$	1,389		$	-		$	185	$	98		$	9,360

~~Table of Contents~~

*Three Months Ended March 31, 2005*
Electric Operations	$	415		$	1		$	(75	)		n/a		$	5,240
Gas Distribution		403			-			60			n/a			1,479
Gas Transmission		57			124			7			n/a			319
Retail Gas Marketing		239			-			n/a		$	22			168
Energy Marketing		152			19			n/a			(1	)		77
All Other		16			74			n/a			(63	)		601
Adjustments/Eliminations		(16	)		(218	)		36			143			1,059
Consolidated Total	$	1,266		$	-		$	28		$	101		$	8,943

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

~~Table of Contents~~

~~SCANA CORPORATION~~

ITEM 2. MANAGEMENT’S DISCUSSIONAND ANALYSIS OF

FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

SCANA CORPORATION

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.~~2005.

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.

~~Table of Contents~~

~~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 at~~www.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~~MARCH 31, 2006

AS COMPARED TO THE CORRESPONDING ~~PERIODS~~PERIOD IN ~~2004~~2005

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:

	First Quarter
	2006		2005
Reported (GAAP) earnings per share:	$	.85	$	.89
Deduct:
Cumulative effect of accounting change, net of tax		.05		-

GAAP-adjusted net earnings per share from operations	$	.80	$	.89

~~Table of Contents~~

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~~Earnings per share before the cumulative effect of ~~adjustments:~~

~~The charge related~~accounting change decreased primarily due to ~~pending litigation recognized~~decreases in ~~2004 resulted from an unfavorable verdict~~electric margins of $.02, decreases in ~~a case in which an unsuccessful bidder for~~gas margins of $.05 and the ~~purchase~~effects of ~~certain~~dilution of ~~SCANA’s propane gas assets in 1999 alleged breach~~$.02. Accelerated depreciation on the Lake Murray back-up dam and recognition of ~~contract~~synthetic fuel tax credits 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 $.13~~items had no effect on net income, as discussed below. Earnings per share ~~charge. The Company’s investment in Knology was monetized in December 2004. The 2005 realized gain on telecommunications investment~~attributable to the cumulative effect of ~~$.03~~accounting change resulted from the ~~receipt in 2005~~Company’s adoption of ~~additional proceeds~~Statement of Financial Accounting Standard (SFAS) 123(R), "Share-Based Payment." See Note 1B to the condensed consolidated financial statements.

The non-GAAP measure, GAAP-adjusted net earnings from operations, provides a consistent basis upon which to measure performance by excluding the effects on per share earnings of the cumulative effect of the accounting change resulting from the ~~2003 sale~~Company’s adoption of ~~the Company’s investment in ITC Holding Company. These additional proceeds had been held in escrow pending resolution of certain contingencies.~~

SFAS 123(R). Management believes that ~~all of~~ the ~~above adjustments are~~cumulative effect adjustment is 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~~South Carolina Electric & Gas Company (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~~Public Service Commission of South Carolina (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.~~

~~Table of Contents~~

~~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 in a January 2005 order, 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 being 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~~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. In addition, SCE&G is allowed to record non-cash carrying costs on the unrecovered ~~investment, which is described further at~~~~Other Income.~~~~See also Other Matters - Synthetic Fuel.~~investment. The accelerated depreciation, synthetic fuel tax credits, partnership losses and the income tax benefit arising from such losses recognized by SCE&G during the three months ended March 31, 2006 and 2005 are as follows:

	Recognized						First Quarter
Factors Increasing (Decreasing)	3rd Quarter			Year to Date
Net Income (millions)	2005			2005
Millions of dollars							2006			2005

Depreciation and amortization expense	$	(17.2	)	$	(200.8	)	$	(0.2	)	$	(169.7	)

Income tax benefits:
From synthetic fuel tax credits		12.9			168.1			3.3			144.0
From accelerated depreciation		6.6			76.8			0.1			64.9
From partnership losses		1.3			27.2			2.0			24.3
Total income tax benefits		20.8			272.1			5.4			233.2

Losses from Equity Method Investments		(3.6	)		(71.3	)		(5.2	)		(63.5	)

Impact on Net Income		-			-		$	-		$	-

The 2005 amounts above reflect the recognition of previously deferred tax credits, while the 2006 amounts reflect the likelihood that credits available in 2006 will be phased down pursuant to regulations which limit the credits based on the relative commodity price of crude oil. See also discussion in Regulatory Matters.

Pension Income

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

	Third Quarter				Year to Date				First Quarter
Millions of dollars	2005		2004		2005		2004		2006		2005

Income Statement Impact:
Reduction in employee benefit costs	$	0.9	$	0.4	$	3.2	$	2.2	$	0.2	$	1.2
Other income		3.0		3.1		9.0		8.1		3.0		3.0
Balance Sheet Impact:
Reduction in capital expenditures		0.2		0.1		0.9		0.7		0.1		0.4
Component of amount due to Summer Station co-owner		0.1		0.1		0.4		0.3		0.1		0.1
Total Pension Income	$	4.2	$	3.7	$	13.5	$	11.3	$	3.4	$	4.7

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.~~

~~Table of Contents~~Other Income

~~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,~~March 31, 2006 and 2005 is a recovery of carrying costs through synthetic fuel tax credits of ~~approximately $2.8~~$2.0 million and ~~$8.4~~$3.0 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:~~2006:

Declaration Date	Dividend Per Share	Record Date	Payment Date

February ~~17, 2005~~16, 2006	$~~.39~~.42	March 10, ~~2005~~2006	April 1, ~~2005~~2006
~~May 5, 2005~~April 27, 2006	$~~.39~~.42	June ~~10, 2005~~9, 2006	July ~~1, 2005~~
~~July 27, 2005~~	~~$.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							First Quarter
Millions of dollars	2005		% Change			2004		2005		% Change			2004		2006		% Change			2005

Operating revenues	$	615.6		25.1	%	$	491.9	$	1,468.5		12.4	%	$	1,306.4	$	398.7		(4.0	)%	$	415.3
Less: Fuel used in generation		217.1		56.0	%		139.2		482.1		35.9	%		354.7		117.5		(8.1	)%		127.8
Purchased power		11.5		7.5	%		10.7		29.1		(32.6	)%		43.2		3.7		(44.0	)%		6.6
Margin	$	387.0		13.1	%	$	342.0	$	957.3		5.4	%	$	908.5	$	277.5		(1.2	)%	$	280.9

~~Third Quarter~~

Margin ~~increased~~decreased by ~~$16.8~~$12.2 million due to ~~favorable~~unfavorable weather, offset primarily by ~~$12.9 million due to increased retail electric rates that went into effect in January 2005, by $7.8~~$5.9 million due to customer growth and by ~~$7.3~~$2.5 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.

~~Table of Contents~~

Gas Distribution

~~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							First Quarter
Millions of dollars	2005		% Change			2004		2005		% Change			2004		2006		% Change			2005

Operating revenues	$	139.7		22.4	%	$	114.1	$	711.0		14.1	%	$	623.0	$	445.8		10.7	%	$	402.8
Less: Gas purchased for resale		103.4		28.1	%		80.7		520.3		17.5	%		442.7		335.7		14.7	%		292.8
Margin	$	36.3		8.7	%	$	33.4	$	190.7		5.8	%	$	180.3	$	110.1		0.1	%	$	110.0

~~Third Quarter~~Mild weather and ~~Year to Date~~conservation efforts in the wake of high commodity prices were offset by customer growth, resulting in similar margins for the periods.

~~Margin increased primarily due to customer growth.~~Gas Transmission

~~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							First Quarter
Millions of dollars	2005		% Change			2004		2005		% Change			2004		2006		% Change			2005

Operating revenues	$	123.1		16.2	%	$	105.9	$	426.0		8.6	%	$	392.1	$	221.8		22.5	%	$	181.0
Less: Gas purchased for resale		110.2		18.2	%		93.2		386.0		9.8	%		351.6		206.5		24.5	%		165.9
Margin	$	12.9		1.6	%	$	12.7	$	40.0		(1.2	)%	$	40.5	$	15.3		1.3	%	$	15.1

~~Third Quarter~~

Margin increased primarily ~~as a result of higher margins on industrial customers.~~due to increased transportation demand revenues.

~~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~~

	First Quarter
Millions of dollars	2006		% Change			2005

Operating revenues	$	270.6		13.3	%	$	238.9
Net income		21.4		(4.0	)%		22.3

~~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.~~

~~Table of Contents~~

~~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~~lower sales margins, which were partially offset by lower operating, marketing and customer service ~~expenses offsetting higher margins.~~expenses.

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							First Quarter
Millions of dollars	2005		% Change			2004		2005		% Change			2004		2006		% Change			2005

Operating revenues	$	307.7		*		$	100.6	$	644.2		48.4	%	$	434.2	$	215.9		26.6	%	$	170.6
Net income	$	1.9		58.3	%	$	1.2	$	0.9		*		$	0.2
Net loss																-		*			(0.8	)

* ~~Greater than 100%~~Not meaningful.

~~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~~loss decreased 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~~

	First Quarter
Millions of dollars	2006		% Change			2005

Other operation and maintenance	$	156.6		(1.4	)%	$	158.9
Depreciation and amortization		76.3		(68.8	)%		244.8
Other taxes		38.7		(1.3	%		38.2
Total	$	271.6		(38.5	)%	$	441.9

Other operation and maintenance expenses increased primarily due to increased electric generation, transmission and ~~gas~~ distribution expenses, ~~of $4.3 million, increased~~which were partially offset by lower operating, marketing and customer ~~billing expense of $1.0 million and higher~~service expenses ~~related to regulatory matters of $1.3 million and increased amortization of regulatory assets of $0.8 million.~~in Retail Gas Marketing. Depreciation and amortization ~~increased approximately $17.2~~decreased $169.5 million due to accelerated depreciation of the back-up dam at Lake Murray in 2005 (previously explained atRecognition of Synthetic Fuel Tax ~~Credits~~Credits) ) and ~~increased $1.4 million~~the lower levels of credits recognized in 2006 due to ~~normal net property additions. In addition, as a result~~applicability of the ~~January 2005 rate order, SCE&G received approval to amortize previously deferred purchased power costs~~phase down provisions as discussed above and ~~to implement new depreciation rates, resulting~~ in ~~$4.1 million of additional depreciation and amortization expense in the period.~~Regulatory Matters.

~~Year to Date~~Income Taxes

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 at~~Recognition 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.

~~Table of Contents~~

~~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~~

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~~March 31, 2006 was ~~2.00.~~2.91.

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

For more information on significant rate and other regulatory matters, see Note 2 to the condensed consolidated financial statements.

The following table summarizes how the Company generated and used funds for property additions and construction expenditures during the three months ended March 31, 2006 and 2005:

	Three Months Ended
	March 31,
Millions of dollars	2006			2005

Net cash provided from operating activities	$	219		$	187
Net cash provided from (used for) financing activities		(69	)		151
Cash and cash equivalents available at the beginning of the period		62			119

Funds used for utility property additions and construction expenditures		(83	)		(121	)
Funds used for nonutility property additions		(10	)		(3	)
Funds used for investments		(10	)		(4	)

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.

Pursuant to Section 204 of the Federal Power Act, SCE&G and GENCO must obtain the Federal Energy Regulatory Commission (FERC) authority to issue short-term debt. Effective February 8, 2006 the FERC has authorized SCE&G and GENCO to issue up to $700 million and $100 million, respectively, of unsecured promissory notes or commercial paper with maturity dates of one year or less. This authorization expires February 7, 2008.

ENVIRONMENTAL MATTERS

For information on environmental matters, see Note 4B to the condensed consolidated financial statements.

REGULATORY MATTERS

Carolina Gas Transmission Corporation

In 2006, SCANA expects to merge two of its subsidiaries, SCPC and SCG Pipeline, Inc., into a new company to be called Carolina Gas Transmission Corporation (CGTC). CGTC is intended to operate as an open access transportation-only interstate pipeline company. On February 27, 2006, the merger application was filed with FERC. The application requests that FERC approve the merger in time for CGTC to commence operations prior to the 2006-2007 winter heating season, which begins November 1, 2006.

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. In a January 2005 order, the SCPSC ~~granted~~approved SCE&G’s request to apply these tax credits, net of partnership losses and other expenses, 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 being 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 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 availability of 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 calculated portion of the credits would be available.

The benchmark price range for 2005, published in April 2006, is $53 to $67 per barrel, and no phase-out applied. However, SCE&G’s analysis indicates that the available synthetic fuel tax credits for 2006 are likely to be impacted by the phase-out calculation. As such, the Company recorded synthetic fuel tax credits and applied those credits to allow the recording of accelerated depreciation related to the balance in the dam remediation project account based on an estimate that only 43 percent of credits generated will be available (phase-out of 57 percent). 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, there is significant uncertainty as to the continued availability of the credits in 2006 and 2007. The availability of these synthetic fuel tax credits is also subject to coal availability and other operational risks related to the generating plants.

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 March 31, 2006, remaining unrecovered costs, based on management’s recording of accelerated depreciation and related tax benefits, were $91.4 million.

Finally, Primesouth, Inc., a subsidiary of SCANA, provides management and maintenance services for a non-affiliated synthetic fuel production facility. Should synthetic fuel tax credit availability be reduced under the above phase-out provisions to the point that production volumes are also reduced, the level of payment Primesouth receives for these services could be adversely impacted.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

As of March 31, 2006			Expected Maturity Date
Millions of dollars
						There-		Fair
Liabilities	2006	2007	2008	2009	2010	After	Total	Value

Long-Term Debt:
Fixed Rate ($)	174.4	68.6	158.6	143.6	50.3	2,517.9	3,113.4	3,108.8
Average Fixed Interest Rate (%)	8.50	6.96	6.13	6.39	6.07	6.14	6.30	n/a
Variable Rate ($)			100.0				100.0	100.0
Average Variable Interest Rate (%)			4.56				4.56	n/a

Interest Rate Swaps:
Pay Variable/Receive Fixed ($)	3.2	28.2	3.2	3.2	3.2	6.4	47.4	(0.4)
Average Pay Interest Rate (%)	8.15	8.02	8.15	8.15	8.15	8.15	8.07	n/a
Average Receive Interest Rate (%)	8.75	7.11	8.75	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	Sold Put
2006	Long ($)	Short ($)		(Long) ($)	(Long) ($)

Settlement Price ^(a)	8.12	9.46	Strike Price ^(a)	9.75	7.07
Contract Amount	11.8	1.8	Contract Amount	0.1	0.2
Fair Value	10.7	1.7	Fair Value	-	-

2007

Settlement Price ^(a)	10.63	10.71	Strike Price ^(a)	-	-
Contract Amount	2.8	1.4	Contract Amount	-	-
Fair Value	2.7	1.4	Fair Value	-	-

^(a)Weighted average

Swaps	2006	2007

Commodity Swaps:
Pay fixed/receive variable ($)	59.8	26.1
Average pay rate ^(a)	9.228	9.562
Average received rate ^(a)	8.215	10.307

Pay variable/receive fixed ($)	0.7	-
Average pay rate ^(a)	8.028	-
Average received rate ^(a)	10.324	-

Basis Swaps:
Pay variable/receive variable ($)	56.7	-
Average pay rate ^(a)	7.661	-
Average received rate ^(a)	7.653	-

^(a)Weighted average

SOUTH CAROLINA ELECTRIC & GAS COMPANY

FINANCIAL SECTION

ITEM 1. FINANCIAL STATEMENTS

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,			December 31,
Millions of dollars	2006			2005
Assets
Utility Plant In Service	$	7,735		$	7,687
Accumulated Depreciation and Amortization		(2,329	)		(2,285	)
		5,406			5,402
Construction Work in Progress		174			160
Nuclear Fuel, Net of Accumulated Amortization		26			28
Utility Plant, Net		5,606			5,590

Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation		28			28
Assets held in trust, net - nuclear decommissioning		53			52
Other investments		26			28
Nonutility Property and Investments, Net		107			108

Current Assets:
Cash and cash equivalents		21			19
Receivables, net of allowance for uncollected accounts of $2 and $2		309			366
Receivables - affiliated companies		27			32
Inventories (at average cost):
Fuel		67			62
Materials and supplies		77			72
Emission allowances		53			54
Prepayments and other		22			12
Deferred income taxes		23			22
Total Current Assets		599			639

Deferred Debits and Other Assets:
Environmental		18			18
Pension asset, net		306			303
Due from affiliates - pension and postretirement benefits		24			31
Other regulatory assets		537			566
Other		124			121
Total Deferred Debits and Other Assets		1,009			1,039
Total	$	7,321		$	7,376

	March 31		December 31,
Millions of dollars	2006		2005
Capitalization and Liabilities

Shareholders’ Investment:
Common equity	$	2,372	$	2,362
Preferred stock (Not subject to purchase or sinking funds)		106		106
Total Shareholders’ Investment		2,478		2,468
Preferred Stock, net (Subject to purchase or sinking funds)		8		8
Long-Term Debt, net		1,849		1,856
Total Capitalization		4,335		4,332

Minority Interest		84		82

Current Liabilities:
Short-term borrowings		348		303
Current portion of long-term debt		183		183
Accounts payable		77		84
Accounts payable - affiliated companies		100		142
Customer deposits and customer prepayments		34		35
Taxes accrued		65		140
Interest accrued		30		35
Dividends declared		41		40
Other		31		38
Total Current Liabilities		909		1,000

Deferred Credits and Other Liabilities:
Deferred income taxes, net		813		801
Deferred investment tax credits		119		119
Asset retirement obligations		313		309
Other asset removal costs		406		404
Due to affiliates - pension and postretirement benefits		12		12
Postretirement benefits		150		148
Other regulatory liabilities		106		94
Other		74		75
Total Deferred Credits and Other Liabilities		1,993		1,962
Commitments and Contingencies (Note 3)		-		-
Total	$	7,321	$	7,376

See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended
	March 31,
Millions of dollars	2006			2005

Operating Revenues:
Electric	$	399		$	416
Gas		193			157
Total Operating Revenues		592			573

Operating Expenses:
Fuel used in electric generation		117			128
Purchased power		4			7
Gas purchased for resale		153			121
Other operation and maintenance		115			108
Depreciation and amortization		65			233
Other taxes		35			35
Total Operating Expenses		489			632

Operating Income (Loss)		103			(59	)

Other Income (Expense):
Other revenues		35			33
Other expenses		(31	)		(30	)
Allowance for equity funds used during construction		-			3
Interest charges, net of allowance for borrowed funds
used during construction of $1 and $1		(36	)		(37	)
Total Other Expense		(32	)		(31	)

Income (Loss) Before Income Taxes (Benefit), Losses from Equity Method
Investments, Minority Interest, Cumulative Effect of Accounting Change
and Preferred Stock Dividends		71			(90	)
Income Tax Expense (Benefit)		18			(207	)

Income Before Losses from Equity Method Investments,
Minority Interest, Cumulative Effect of Accounting Change
and Preferred Stock Dividends		53			117
Losses from Equity Method Investments		(6	)		(64	)
Minority Interest		(1	)		(1	)
Cumulative Effect of Accounting Change, net of taxes		4			-

Net Income		50			52
Preferred Stock Cash Dividends Declared		2			2

Earnings Available for Common Shareholder	$	48		$	50

See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended
	March 31,
Millions of dollars	2006			2005
Cash Flows From Operating Activities:
Net income	$	50		$	52
Adjustments to Reconcile Net Income to Net Cash Provided From Operating Activities:
Cumulative effect of accounting change, net of taxes		(4	)		-
Losses from equity method investments		6			64
Minority interest		1			1
Depreciation and amortization		65			233
Amortization of nuclear fuel		5			6
Carrying cost recovery		(2	)		(3	)
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		62			37
Inventories		(22	)		(48	)
Prepayments		(10	)		(10	)
Pension asset		(3	)		(5	)
Other regulatory assets		8			(18	)
Deferred income taxes, net		11			(47	)
Regulatory liabilities		12			(133	)
Postretirement benefits		2			2
Accounts payable		(43	)		(1	)
Taxes accrued		(75	)		(122	)
Interest accrued		(5	)		2
Changes in fuel adjustment clauses		22			5
Changes in other assets		2			6
Changes in other liabilities		(6	)		(14	)
Net Cash Provided From Operating Activities		76			7
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(68	)		(113	)
Investments		(3	)		(4	)
Net Cash Used For Investing Activities		(71	)		(117	)
Cash Flows From Financing Activities:
Proceeds from issuance of debt		-			97
Repayment of debt		(7	)		(2	)
Dividends on equity securities		(39	)		(37	)
Contribution from parent		1			23
Short-term borrowings - affiliate, net		(3	)		(4	)
Short-term borrowings, net		45			30
Net Cash Provided From (Used For) Financing Activities		(3	)		107
Net Increase (Decrease) In Cash and Cash Equivalents		2			(3	)
Cash and Cash Equivalents, January 1		19			20
Cash and Cash Equivalents, March 31	$	21		$	17
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $1 and $1)	$	36		$	37
- Income taxes		10			48
Noncash Investing and Financing Activities:
Accrued construction expenditures		21			13
See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2006

(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, 2005. These are interim financial statements, and due to the seasonality of the Company’s business and matters that may occur during the rest of the year, 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 ~~composite increase~~controlling financial interest in ~~retail~~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 power purchase and related operating agreements. 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 $258 million) serves as collateral for its long-term borrowings.

B. Basis of Accounting

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

	March 31,		December 31,
Millions of dollars	2006		2005
Regulatory Assets:
Accumulated deferred income taxes	$	170	$	170
Under-collections - electric fuel and gas cost adjustment clauses		30		56
Deferred purchased power costs		15		17
Deferred environmental remediation costs		18		18
Asset retirement obligations and related funding		245		240
Franchise agreements		55		56
Deferred regional transmission organization costs		10		11
Other		12		16
Total Regulatory Assets	$	555	$	584

Regulatory Liabilities:
Accumulated deferred income taxes	$	35	$	36
Other asset removal costs		406		404
Storm damage reserve		40		38
Planned major maintenance		14		9
Other		17		11
Total Regulatory Liabilities	$	512	$	498

Under-collections - electric fuel and gas cost adjustment clauses, 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 represent 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 a three-year period 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 SCE&G. Costs incurred by SCE&G at such sites are being recovered through rates, of which $17.5 million remain to be recovered.

Asset retirement obligations (AROs) and related funding represent the regulatory asset associated with the legal obligation to decommission and dismantle V. C. Summer Nuclear Station (Summer Station) and conditional AROs recorded as required by SFAS 143,“Accounting for Asset Retirement Obligations,” and Financial Accounting Standards Board Interpretation (FIN) 47, “Accounting for Conditional Asset Retirement Obligations.”

Deferred regional transmission organization costs represent costs incurred by SCE&G in the United States Federal Energy Regulatory Commission (FERC)-mandated formation of ~~approximately $41.4 million based on a test year calculation.~~GridSouth. 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~~project was suspended in 2002. Effective January ~~2005. As part of its order,~~2005, the SCPSC approved the amortization of these amounts through cost of service rates over approximately five years.

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

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 three months ended March 31, 2006, no amounts were drawn from this reserve account.

Planned major maintenance related to certain fossil and hydro-turbine equipment and nuclear refueling outages is accrued in advance of the time the costs are incurred. SCE~~&G's~~&G is allowed to collect $8.5 million annually over an eight-year period through electric rates to offset turbine maintenance expenditures. Nuclear refueling charges are accrued during each 18-month refueling outage cycle based on an SCPSC accounting order. Nuclear refueling charges do not receive special rate consideration.

The SCPSC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not 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 ~~construction~~deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and ~~operating costs~~could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company’s results of operations, liquidity or financial position in the period the write-off would be recorded.

C. Transactions with Affiliates

SCE&G has entered into agreements with certain affiliates to purchase all gas for resale to its distribution customers. SCE~~&G's new~~&G purchases natural gas for resale and for electric generation from South Carolina Pipeline Corporation (SCPC) and had $39.5 million and $72.1 million payable to SCPC for such gas purchases at March 31, 2006 and December 31, 2005, respectively.

SCE&G purchases natural gas and related pipeline capacity to supply its Jasper County Electric Generating Station ~~recovery~~from SCANA Energy Marketing, Inc. (SEMI). Such purchases totaled $7.1 million and $20.0 million for the three months ended March 31, 2006 and 2005, respectively. SCE&G had $8.0 million payable to SEMI for such purposes as of ~~costs~~December 31, 2005. There was no such payable balance as of ~~mandatory environmental upgrades primarily~~March 31, 2006.

SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel. The Company’s receivables from these affiliated companies were $27.1 million and $24.6 million at March 31, 2006 and December 31, 2005, respectively. SCE&G’s payables to these affiliated companies were $28.0 million and $25.3 million at March 31, 2006 and December 31, 2005, respectively. SCE&G purchased $64.8 million and $50.9 million of synthetic fuel from these affiliated companies for the three months ended March 31, 2006 and 2005, respectively.

In the three months ended March 31, 2005, the Company purchased 82 miles of gas distribution pipeline from SCPC at its net book value, which totaled $4.6 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	2006			2005			2006			2005
*Three months ended March 31,*
Service cost	$	3.5		$	3.0		$	1.2		$	0.9
Interest cost		9.9			9.5			2.8			2.8
Expected return on assets		(18.8	)		(19.1	)		-			-
Prior service cost amortization		1.7			1.7			0.2			0.3
Transition obligation amortization		0.1			0.2			0.2			0.2
Amortization of actuarial loss		0.2			-			0.3			0.4
Amount attributable to Company affiliates		(0.6	)		(0.4	)		(1.3	)		(1.2	)
Net periodic benefit (income) cost	$	(4.0	)	$	(5.1	)	$	3.4		$	3.4

E. Equity Compensation Plan

The Company participates in the SCANA Corporation Long-Term Equity Compensation Plan. The SCANA Corporation Long-Term Equity Compensation Plan provides for grants of incentive and nonqualified stock options, stock appreciation rights, restricted stock, performance shares and performance units to certain key employees and non-employee directors. The plan currently authorizes the issuance of up to five million shares of the Company’s common stock, no more than one million of which may be granted in the form of restricted stock.

SFAS 123 (revised 2004),“Share-Based Payment,” (SFAS 123(R)) requires compensation costs related to ~~Federal Clean Air Act regulations~~share-based payment transactions to be recognized in the financial statements. With limited exceptions, compensation cost is measured based on the grant-date fair value of the instruments issued and is 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.” The cumulative effect of the adoption of SFAS 123(R) on January 1, 2006 resulted in a $4 million (net of tax) gain in the first quarter of 2006 based on a reduction of prior compensation accruals for performance awards (discussed below) granted in 2004 and 2005.

Liability Awards

Certain executives are granted a target number of performance shares on an annual basis that vest over a three-year period. Each performance share has a value that is equal to, and changes with, the value of a share of SCANA common stock, and dividend equivalents are accrued on, and reinvested in, the performance shares. Payout of performance share awards is determined by SCANA's performance against pre-determined measures of total shareholder return (TSR) as compared to a peer group of utilities (weighted 60%) and growth in earnings per share (weighted 40%) over the three year plan cycle. TSR is calculated by dividing stock price increase over the three year period, plus cash dividends, by the stock price as of the beginning of the period. Payouts vary according to SCANA's ranking against the peer group and relative earnings per share projection achievement. Awards are designated as target shares of SCANA common stock and may be paid in stock or cash or a combination of stock and cash at SCANA's discretion.

Compensation expense recognized in the Statements of Income for performance awards, exclusive of the cumulative effect adjustment discussed previously, totaled $0.7 million and $1.3 million for the three months ended March 31, 2006 and 2005, respectively. In addition, compensation cost of less than $0.1 million was capitalized during the three months ended March 31, 2006 and 2005.

Equity Awards

A summary of activity related to nonqualified stock options since December 31, 2005 follows:

	Number of Options	Weighted Average Exercise Price
Outstanding-December 31, 2005	439,270	$27.53
Exercised	(11,341)	27.09
Outstanding-March 31, 2006	427,929	27.54

No stock options have been granted since August 2002, and all outstanding options have been fully vested since August 2005. The options expire ten years after the grant date. At March 31, 2006, all outstanding options were currently exercisable at prices ranging from $25.50-$29.60, and had a weighted-average remaining contractual life of 5.6 years.

The exercise of stock options during the period was satisfied using original issue shares of the SCANA’s common stock. Cash and the related tax benefits realized from stock option exercises during the period were retained at SCANA.

All options 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 was 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(R), pro forma earnings available for the common shareholder would have been unchanged from that reported for the three months ended March 31, 2005.

F. New Accounting Matters

SFAS 154, “Accounting Changes and Error Corrections,” was issued in June 2005. It requires retrospective application to financial statements of ~~current~~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 ~~anticipated net synthetic~~SFAS 3, “Reporting Accounting Changes in Interim Financial Statements,” although it carries forward some of their provisions. The Company adopted SFAS 154 in the first quarter of 2006. There was no material impact on the Company’s results of operations, cash flows or financial position.

SFAS 123(R),“Share-Based Payment,” was issued in December 2004 and requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, compensation cost is measured based on the grant-date fair value of the instruments issued and is 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.” The Company adopted SFAS 123(R) in the first quarter of 2006. The impact on the Company’s results of operations is discussed at Note 1E.

G. Reclassifications

Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2006.

2.RATE AND OTHER REGULATORY MATTERS

Electric

SCE&G's rates are established using a cost of fuel ~~tax credits~~component approved by the SCPSC which may be modified periodically to ~~offset~~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, 2005 through March 31, 2006 was as follows:

Rate Per KWh	Effective Date
$.01764	January-April 2005
$.02256	May 2005-March 2006

On April 11, 2006, as part of the annual review of fuel costs, the SCPSC approved SCE&G’s request to increase the cost of ~~constructing~~fuel component from $.02256 per KWh to $.02516 per KWh effective the ~~back-up dam at Lake Murray (as~~first billing cycle in May 2006. In connection with the increase, SCE&G agreed to spread the recovery of previously ~~discussed in~~~~Recognition~~under-collected fuel costs of ~~Synthetic Fuel Tax Credits~~~~). The SCPSC also approved recovery~~$38.5 million 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.two-year period.

Gas

~~In October 2005 the SCPSC approved an increase in~~ SCE~~&G’s~~&G's rates are established using a cost of gas component ~~from a rate~~approved by the SCPSC which may be modified periodically to reflect changes in the price of ~~$.903 per therm for all customer classes to rates~~natural gas purchased by SCE&G. SCE&G's cost of ~~$1.29729, $1.22218 and $1.19823 per therm~~gas component for residential, small and medium general service and large general ~~services~~service classes ~~respectively. These new rates are effective~~were as follows (rate per therm):

Effective Date	Residential		Small/Medium		Large
January-October 2005	$	.903	$	.903	$	.903
November 2005		1.297		1.222		1.198
December 2005		1.362		1.286		1.263
January 2006		1.297		1.222		1.198
February-March 2006		1.227		1.152		1.128

~~Table of Contents~~

3. 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, 2005. Commitments and contingencies at March 31, 2006 include the following:

A. Nuclear Insurance

The ~~following table summarizes how~~Price-Anderson Indemnification Act deals with public liability for a nuclear incident and establishes the ~~Company generated~~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 $67.1 million per incident, but not more than $10 million per year.

SCE&G currently maintains policies (for itself and ~~used funds~~on behalf of Santee Cooper, a one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property ~~additions~~damage, excess property damage and ~~construction expenditures during~~outage costs, permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the ~~nine months ended September 30, 2005 and 2004:~~current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $15.6 million.

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~~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 ~~various securities, including long-term~~insurance, or to the extent such insurance becomes unavailable in the future, 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~~extent that SCE&G’s rates would not recover the cost of any purchased replacement power, SCE&G ~~Fuel Company and PSNC Energy~~will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident. However, if such an incident 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~~occur, it would have a ~~representation as to “no~~ material adverse ~~change” related to financial condition or material litigation at~~impact on the ~~time of a borrowing, and none of the facilities contains covenants based on credit ratings under which lenders could refuse to advance funds.~~

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'sCompany’s results of operations, cash flows orand financial position.

~~In March 2005 SCANA issued $100~~B. Environmental

On January 28, 2004, SCE&G and Santee Cooper filed suit in the Court of Federal Claims against the Department of Energy (DOE) for breach of contract. The contract, entered into in 1983, known as the Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (Standard Contract) required the federal government to accept and dispose of spent nuclear fuel and high-level radioactive waste beginning not later than January 31, 1998, in exchange for agreed payments fixed in the Standard Contract at particular amounts. As of the date of filing, the federal government has accepted no spent fuel from Summer Station or any other utility for transport and disposal, and has indicated that it does not anticipate doing so until 2010, at the earliest. As a consequence of the federal government’s breach of contract, the plaintiffs have incurred and will continue to incur substantial costs. On January 9, 2006, SCE&G and Santee Cooper accepted a settlement from DOE which required the payment by DOE of $9 million ~~in senior unsecured floating rate medium-term notes maturing~~to the plaintiffs. The payment reimbursed the plaintiffs for certain costs incurred from January 31, 1998 through July 31, 2005. The settlement also provides for the plaintiffs to submit an annual application to DOE for the reimbursement of certain costs incurred subsequent to July 31, 2005. SCE&G received the settlement 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 $2002006, and recorded its $6 million ~~of floating rate medium-term notes due to mature in November 2006.~~

~~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~~portion of the ~~project and related activities cost approximately $275 million, excluding AFC.~~settlement as a reduction to the under-collections-electric fuel adjustment clause.

~~Table of Contents~~

~~ENVIRONMENTAL MATTERS~~

~~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.

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.

~~Table of Contents~~

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.

~~Table of Contents~~

~~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.~~

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

~~Table of Contents~~

~~SOUTH CAROLINA ELECTRIC& GAS COMPANY~~

~~FINANCIAL SECTION~~

~~Table of Contents~~

~~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

~~Table of Contents~~

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.~~

~~Table of Contents~~

~~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.

~~Table of Contents~~

~~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.

~~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 )

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.

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.

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.

~~Table of Contents~~

~~C. Transactions with Affiliates~~

SCE&G has ~~entered into agreements~~been named, along with ~~certain affiliates~~27 others, by the EPA as a potentially responsible party (PRP) at the Carolina Transformer Superfund site located in Fayetteville, North Carolina. The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from 1967 to ~~purchase all gas for resale to its distribution customers and to purchase electric energy.~~1984. During that time, 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 companiesoccasionally used CTC for the ~~three months ended September 30, 2005~~repair of existing transformers and ~~2004, respectively.~~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 purchased approximately $183.9 million~~&G’s records indicate that only minimal quantities of used transformers were shipped to CTC, and ~~$142.9 million of synthetic fuel from these affiliated companies~~it is not clear if any contained PCB-contaminated oil. Although a basis for the ~~nine months ended September 30, 2005 and 2004, respectively.~~

Inallocation of clean-up costs among 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.”~~

~~Table of Contents~~

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~~28 PRPs 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~~unclear, SCE&G does not ~~expect~~believe that ~~the initial adoption will~~its involvement at this site would result in an allocation of costs that would have a material adverse impact on ~~the Company’s~~its 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 compensationcondition. Any 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.~~

~~Table of Contents~~

~~2. RATE AND OTHER REGULATORY MATTERS~~

~~Electric~~

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

~~Gas~~

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

~~Table of Contents~~

~~3. DEBT AND CREDIT FACILITIES~~

~~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.

~~Table of Contents~~

~~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 believethis matter 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~~SCE&G has been named, along with 53 others, by the EPA ~~issued~~as a ~~final rule establishing~~PRP at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia. The EPA placed the site on the National Priorities List on April 19, 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned. While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels. During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. EPA and the State of Georgia have documented that a ~~mercury emissions cap~~release or releases have occurred at the site leading to contamination of groundwater, surface water and ~~trade program~~soils. EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The site has not been cleaned up nor has a cleanup cost been estimated. Although a basis for ~~coal-fired power plants~~the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that ~~requires limits to be met~~its involvement at this site would result in ~~two phases, in 2010 and 2018. The Company~~an allocation of costs that would have a material impact on its results of operations, cash flows or financial condition. Any cost arising from this matter 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.

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,~~March 31, 2006, SCE&G had spent ~~approximately $4.3~~$4.5 million related to these three sites, and expects to spend an additional ~~$8.2~~$11.5 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 Any cost arising from ~~1967~~this matter is expected 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.be recoverable through rates.

~~Table of Contents~~

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~~nonutility 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. It is anticipated that this case may go to trial in 2006. SCE&G is confident of the propriety of its actions and intends to mount a vigorous defense. ~~SCE&G~~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, 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).~~Circuit. The plaintiff alleges ~~that SCE&G~~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 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~~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~~appealed and the plaintiff’s appeal will likely be heard in May. 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.

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.

D.	Other Contingency

~~Table of Contents~~

In the fourth quarter of 2005, SCE&G recorded a loss accrual in the amount of $0.8 million based on its estimation of net revenues from these transactions that occurred after the date of the Settlement and Consent Agreement and that might be deemed to be in violation of FERC's rule on the use of network transmission service and be subject to disgorgement pursuant to FERC orders. SCE&G believes this accrual is a resonable estimate; however, there remains uncertainty as to what actions may be taken by FERC. Potential actions could include further modifications to the compliance plan or other non-monetary remedies. In addition to the disgorgement of profits, such remedies could also include penalties of up to a maximum of $1 million per violation or per day since August 8, 2005, the effective date of the Energy Policy Act of 2005. In light of SCE&G's self-reporting and other cooperation in the investigation of this matter, SCE&G's belief that no market participants or customers of SCE&G were harmed or disadvantaged by the transactions, and SCE&G’s institution of appropriate safeguards referred to above, SCE&G does not believe that such sanctions are warranted. Nonetheless, SCE&G cannot predict what, if any, actions FERC will take with respect to this matter, and is unable to determine if the resolution of this matter will have a material adverse impact on its operations, cash flows or financial condition.

4. 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~~earnings available to the common shareholder 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,*
																										Earnings (Loss)
																							Operating			Available to
																					External		Income			Common			Segment
Millions of Dollars																					Revenue		(Loss)			Shareholder			Assets
*Three Months Ended March 31, 2006*
Electric Operations	$	1,471	$	194			n/a		$	5,315	$	1,310	$	385			n/a		$	5,256	$	399	$	91			n/a		$	5,408
Gas Distribution		321		5			n/a			388		275		6			n/a			340		193		19			n/a			406
All Other		-		-		$	(72	)		3		-		-		$	(1	)		3		-		-		$	(6	)		3
Adjustments/Eliminations		-		(2	)		264			1,350		-		(2	)		190			1,198		-		(7	)		54			1,504
Consolidated Total	$	1,792	$	197		$	192		$	7,056	$	1,585	$	389		$	189		$	6,797	$	592	$	103		$	48		$	7,321

*Three Months Ended March 31, 2005*
Electric Operations	$	416	$	(75	)		n/a		$	5,240
Gas Distribution		157		17			n/a			359
All Other		-		-		$	(64	)		3
Adjustments/Eliminations		-		(1	)		114			1,255
Consolidated Total	$	573	$	(59	)	$	50		$	6,857

~~Table of Contents~~

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

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.~~2005.

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~~

~~Gas Distribution~~

~~Table of Contents~~

RESULTS OF OPERATIONS

FOR THE THREE ~~AND NINE~~ MONTHS ENDED ~~SEPTEMBER 30, 2005~~MARCH 31, 2006

AS COMPARED TO THE CORRESPONDING ~~PERIODS~~PERIOD IN ~~2004~~2005

Net Income

Net income was as follows:

	Third Quarter				Year to Date				First Quarter
Millions of dollars	2005		2004		2005		2004		2006	2005

Net income	$	105.9	$	84.4	$	197.9	$	195.0	$49.5	$52.1

~~Third Quarter~~

Net income ~~increased by approximately $28.0 million~~decreased primarily due to ~~increases in~~increased electric ~~margins. This increase was~~operating expenses, which were 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~~the favorable impact of the ~~January 2005 rate order, SCE&G received approval to amortize previously deferred purchased power costs~~cumulative effect of an accounting change resulting ~~in $1.3 million~~from the Company’s adoption of ~~additional depreciation expense in~~Statements of Financial Accounting Standards (SFAS) 123(R), "Share-Based Payment." See Note 1E of the ~~period.~~condensed consolidated financial statements. Unfavorable electric margins were mostly offset by favorable gas margins. 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~~South Carolina Electric & Gas Company (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~~Public Service Commission of South Carolina (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 in a January 2005 order, 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 being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

~~Table of Contents~~

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~~Regulatory 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 the three months ended March 31, 2006 and 2005 are as follows:

Factors Increasing (Decreasing) Net Income (millions)	Recognized 3rd Quarter 2005			Year to Date 2005
Factors Increasing (Decreasing)							First Quarter
Net Income (millions)							2006	2005

Depreciation and amortization expense	$	(17.2	)	$	(200.8	)	$(0.2)	$(169.7)

Income tax benefits:
From synthetic fuel tax credits		12.9			168.1		3.3	144.0
From accelerated depreciation		6.6			76.8		0.1	64.9
From partnership losses		1.3			27.2		2.0	24.3
Total income tax benefits		20.8			272.1		5.4	233.2

Losses from Equity Method Investments		(3.6	)		(71.3	)	(5.2)	(63.5)

Impact on Net Income		-			-		$-

Pension Income

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

	Third Quarter				Year to Date				First Quarter
Millions of dollars	2005		2004		2005		2004		2006		2005

Income Statement Impact:
Reduction in employee benefit costs	$	1.2	$	0.8	$	4.2	$	3.1	$	0.6	$	1.5
Other income		3.0		3.2		9.1		8.3		3.2		3.1
Balance Sheet Impact:
Reduction in capital expenditures		0.3		0.2		1.2		0.9		0.2		0.4
Component of amount due to Summer Station co-owner		0.1		0.1		0.4		0.3		0.1		0.1
Total Pension Income	$	4.6	$	4.3	$	14.9	$	12.6	$	4.1	$	5.1

For the last several years, the market value of SCANA’s retirement plan ~~(pension)~~ assets has exceeded the total actuarial present value of accumulated plan benefits. 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

Dividends Declared

SCE&G’s Board of Directors has declared the following dividends on common stock held by SCANA during ~~2005:~~2006:

Declaration Date	Amount	Quarter Ended	Payment Date

February ~~17, 2005~~16, 2006	$~~38.0~~39.2 million	March 31, ~~2005~~2006	April 1, ~~2005~~2006
~~May 5, 2005~~April 27, 2006	$~~38.0~~39.2 million	June 30, ~~2005~~2006	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							First Quarter
Millions of dollars	2005		% Change			2004		2005		% Change			2004		2006		% Change			2005

Operating revenues	$	617.0		25.2	%	$	493.0	$	1,471.0		12.3	%	$	1,309.5	$	399.6		(4.0	)%	$	416.2
Less: Fuel used in generation		217.1		56.0	%		139.2		482.1		35.9	%		354.7		117.5		(8.0	)%		127.7
Purchased power		11.5		7.5	%		10.7		29.1		(32.6	)%		43.2		3.7		(43.9	)%		6.6
Margin	$	388.4		13.2	%	$	343.1	$	959.8		5.3	%	$	911.6	$	278.4		(1.2	)%	$	281.9

~~Third Quarter~~

~~Year to Date~~Gas Distribution

~~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

~~Table of Contents~~

~~Third Quarter and Year to Date~~

	First Quarter
Millions of dollars	2006		% Change			2005

Operating revenues	$	192.8		22.9	%	$	156.9
Less: Gas purchased for resale		153.5		27.2	%		120.7
Margin	$	39.3		8.6	%	$	36.2

Margin increased primarily due to ~~customer growth.~~increased retail base rates which became effective with the first billing cycle in November 2005.

Other Operating Expenses

Other operating expenses were as follows:

	Third Quarter							Year to Date							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004		2006		% Change			2005

Other operation and maintenance	$	111.4		8.3	%	$	102.9	$	332.3		5.5	%	$	315.1	$	114.9		5.9	%	$	108.5
Depreciation and amortization		77.8		36.0	%		57.2		389.0		*			164.6		64.5		(72.4	)%		233.5
Other taxes		32.0		(0.6	)%		32.2		102.9		1.0	%		101.9		35.0		0.3	%		34.9
Total	$	221.2		15.0	%	$	192.3	$	824.2		41.7	%	$	581.6	$	214.4		(43.1	)%	$	376.9

*Greater than 100%

~~Third Quarter~~

Other operation and maintenance expenses increased primarily due to increased electric generation, transmission 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.expenses. Depreciation and amortization ~~increased approximately $17.2~~decreased $169.5 million due to accelerated depreciation of the back-up dam at Lake Murray in 2005 (previously explained atRecognition of Synthetic Fuel Tax Credits) and ~~increased $1.4 million~~the lower levels of credits recognized in 2006 due to ~~normal net property additions. In addition, as a result~~applicability of the ~~January 2005 rate order, SCE&G received approval to amortize previously deferred purchased power costs~~phase down provisions as discussed above and ~~to implement new depreciation rates, resulting~~ in ~~$4.1 million of additional depreciation and amortization expense in the period.~~Regulatory Matters.

~~Year to Date~~Income Taxes

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 at~~Recognition 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~~March 31, 2006 increased primarily due to the initial application and recognition of synthetic fuel tax credits in the first quarter of 2005 and the phase down in 2006, as previously discussed atRecognition of Synthetic Fuel Tax Credits. In addition, certain research and experimentation tax credits of $2.0 million were recognized in the first quarter of 2005 upon the amendment of prior year income tax returns.

~~Table of Contents~~

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~~March 31, 2006 was ~~1.95.~~3.14.

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.

InFor more information on significant rate and other regulatory matters, see Note 2 to the condensed consolidated financial statements.

SCE&G expects to require the addition of base load electrical generation by 2015 and is evaluating alternatives, including fossil and nuclear-fueled generation. On February 10, 2006, SCE&G and Santee Cooper, a ~~January 2005 order~~state-owned utility in South Carolina (joint owners of Summer Station) announced their selection of the ~~SCPSC granted SCE&G~~Summer Station site as the preferred site for a ~~composite increase~~new nuclear plant should nuclear generation be considered the best alternative in ~~retail electric rates~~the future. Due to the significant lead time required for construction of ~~approximately 2.89%, designed~~a nuclear plant, the joint owners are preparing an application to ~~produce additional annual revenues of approximately $41.4 million based on~~the Nuclear Regulatory Commission (NRC) for 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%~~combined construction and operating license (COL). The ~~new rates became effective~~COL application, which is expected to be completed and filed in ~~January 2005. As part~~2007, would be reviewed by the NRC for an estimated three years. Issuance of ~~its order,~~a COL would not obligate the ~~SCPSC approved SCE&G's recovery of~~joint owners to build a nuclear plant. The final decision to build a nuclear plant will be influenced by several factors, including NRC licensing attainment, 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 in~~~~Recognition of Synthetic Fuel Tax Credits~~~~). The SCPSC also approved recovery over a five-year period of SCE&G's approximately $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization~~competing fuels, regulatory 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,environmental requirements and ~~became effective with the first billing cycle in November 2005.~~financial market conditions.

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.

~~Table of Contents~~

The following table summarizes how SCE&G generated and used funds for property additions and construction expenditures during the ~~nine~~three months ended ~~September 30, 2005~~March 31, 2006 and ~~2004:~~2005:

	Nine Months Ended						Three Months Ended
	September 30,						March 31,
Millions of dollars	2005			2004			2006			2005

Net cash provided from operating activities	$	239		$	332		$	76		$	7
Net cash provided from (used for) financing activities		15			(90	)		(3	)		107
Cash provided from sale of assets		1			2
Cash and cash equivalents available at the beginning of the period		20			56			19			20

Funds used for utility property additions and construction expenditures	$	(247	)	$	(269	)		(68	)		(113	)
Funds used for nonutility property additions		-			(5	)
Funds used for investments		(14	)		(14	)		(3	)		(4	)

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~~the SCPSC and the Securities and Exchange Commission.

~~CAPITAL TRANSACTIONS~~Pursuant to Section 204 of the Federal Power Act, SCE&G and GENCO must obtain the Federal Energy Regulatory Commission (FERC) authority to issue short-term debt. Effective February 8, 2006, the FERC has authorized SCE&G and GENCO to issue up to $700 million and $100 million, respectively, of unsecured promissory notes or commercial paper with maturity dates of one year or less. This authorization expires February 7, 2008.

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.

~~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.

~~Table of Contents~~

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 5B4B to the condensed consolidated financial statements.

~~OTHER~~REGULATORY MATTERS

Synthetic Fuel

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, inIn a January 2005 order, the SCPSC approved SCE&G’s request to apply these ~~synthetic fuel~~ tax credits, net of partnership losses and other expenses, 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 being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

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.

The ~~ability to utilize~~availability of 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~~calculated portion 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~~published in April 2006, is $53 to $67 per barrel, and no phase-out applied. However, SCE&G’s analysis indicates that 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 recordavailable synthetic fuel tax credits ~~as they~~for 2006 are ~~generated~~likely to be impacted by the phase-out calculation. As such, the Company recorded synthetic fuel tax credits and ~~to apply~~applied those credits ~~quarterly~~ to allow the recording of accelerated depreciation related to the balance in the dam remediation project ~~account.~~account based on an estimate that only 43 percent of credits generated will be available (phase-out of 57 percent). 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~~there is significant uncertainty as to the continued availability of the credits ~~particularly~~ in 2006 and 2007.

~~Table of Contents~~

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.

~~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,~~March 31, 2006, remaining unrecovered costs, based on management’s recording of accelerated ~~deprecation~~depreciation and related tax benefits, ~~on its reasonable assumption that 2005’s credits will not be subjected to the phase-out provisions,~~ were ~~$98.3~~$91.4 million.

ITEM 3. 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
As of March 31, 2006										As of March 31, 2006
Millions of dollars	Millions of dollars			Expected Maturity Date						Millions of dollars			Expected Maturity Date
							There-		Fair							There-		Fair
Liabilities	2005	2006	2007		2008	2009	after	Total	Value	2006	2007	2008		2009	2010	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	169.9	39.2			139.2	39.2	1,714.4	2,141.1	2,051.3
Average Interest Rate (%)	7.78	8.51	6.86		6.86	6.33	5.88	6.16	n/a	8.51	6.86			6.33	6.86	5.88	6.17	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.

~~Table of Contents~~

PUBLIC SERVICE ~~COMPA~~NYCOMPANY 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).

~~Table of Contents~~

~~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

~~Table of Contents~~

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.~~

~~Table of Contents~~

ITEM 1. FINANCIAL STATEMENTS

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

CONDENSED CONSOLIDATED~~STATEMENTS OF OPERATIONS~~ BALANCE SHEETS

(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

	March 31,			December 31,
Millions of dollars	2006			2005
Assets
Gas Utility Plant	$	1,023		$	1,006
Accumulated Depreciation		(230	)		(282	)
Acquisition Adjustment		210			210
Gas Utility Plant, Net		1,003			934
Nonutility Property and Investments, Net		28			28
Current Assets:
Cash and cash equivalents		4			3
Restricted cash and temporary investments		-			1
Receivables, net of allowance for uncollectible accounts of $3 and $3		114			182
Receivables-affiliated companies		9			9
Inventories (at average cost):
Stored gas		66			92
Materials and supplies		6			6
Other		1			3
Total Current Assets		200			296
Deferred Debits and Other Assets:
Due from affiliate-pension asset		10			11
Regulatory assets		36			26
Other		4			3
Total Deferred Debits and Other Assets		50			40
Total	$	1,281		$	1,298

	March 31,		December 31,
Millions of dollars	2006		2005

Capitalization and Liabilities
Capitalization:
Common equity	$	548	$	528
Long-term debt, net		269		270
Total Capitalization		817		798
Current Liabilities:
Short-term borrowings		41		99
Current portion of long-term debt		3		3
Accounts payable		46		91
Accounts payable-affiliated companies		4		6
Customer deposits and customer prepayments		11		14
Taxes accrued		16		4
Interest accrued		4		6
Distributions/dividends declared		4		4
Deferred income taxes, net		2		3
Other		5		6
Total Current Liabilities		136		236
Deferred Credits and Other Liabilities:
Deferred income taxes, net		104		104
Deferred investment tax credits		1		1
Due to affiliate-postretirement benefits		19		19
Other regulatory liabilities		27		23
Asset retirement obligations		13		13
Other asset removal costs		152		91
Other		12		13
Total Deferred Credits and Other Liabilities		328		264
Commitments and Contingencies (Note 4)		-		-
Total	$	1,281	$	1,298

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended
	March 31,
Millions of dollars	2006			2005
Operating Revenues	$	253		$	246
Cost of Gas		182			172
Gross Margin		71			74

Operating Expenses:
Operation and maintenance		20			20
Depreciation and amortization		9			9
Other taxes		2			2
Total Operating Expenses		31			31

Operating Income		40			43

Other Income (Expense):
Other revenues		4			4
Other expenses		(3	)		(3	)
Interest charges, net of allowance for borrowed funds used during construction		(6	)		(5	)
Total Other Expense		(5	)		(4	)

Income Before Income Taxes, Earnings from Equity Method Investments
and Cumulative Effect of Accounting Change		35			39
Income Tax Expense		14			16

Income Before Earnings from Equity Method Investments and Cumulative Effect of Accounting Change		21			23
Earnings from Equity Method Investments		1			1
Cumulative Effect of Accounting Change, net of taxes		1			-
Net Income	$	23		$	24

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended
	March 31,
Millions of dollars	2006			2005


Cash Flows From Operating Activities:
Net income	$	22		$	24
Adjustments to reconcile net income to net cash provided from operating activities:
Cumulative effect of accounting change, net of taxes		1			-
Excess distributions, net of earnings from equity method investments		-			1
Depreciation and amortization		10			9
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		68			1
Inventories		26			40
Regulatory liabilities		-			1
Accounts payable		(49	)		(22	)
Deferred income taxes, net		(1	)		-
Taxes accrued		12			14
Changes in gas adjustment clauses		(6	)		25
Changes in other assets		2			-
Changes in other liabilities		(6	)		(11	)
Net Cash Provided From Operating Activities		79			82

Cash Flows From Investing Activities:
Construction expenditures, net of AFC		(17	)		(13	)
Nonutility and other		-			7
Net Cash Used For Investing Activities		(17	)		(6	)

Cash Flows From Financing Activities:
Short-term borrowings, net		(58	)		(55	)
Contributions from parent		1			-
Distributions/dividends		(4	)		(4	)
Net Cash Used For Financing Activities		(61	)		(59	)

Net Increase In Cash and Cash Equivalents		1			17
Cash and Cash Equivalents, January 1		3			1
Cash and Cash Equivalents, March 31	$	4		$	18

Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $0.2 and $0.1)	$	7		$	7
- Income taxes		4			2

Noncash Investing and Financing Activities:
Accrued construction expenditures		2			-

See Notes to Condensed Consolidated Financial Statements.

~~Table of Contents~~

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.~~

~~Table of Contents~~

~~PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED~~

NOTESTO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~September 30, 2005~~March 31, 2006

(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.~~2005. These are interim financial statements, and due to the seasonality of the Company’s business and matters that may occur during the rest of the year, 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~~“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~~March 31, 2006 the Company has recorded ~~approximately $18 million and $110 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to~~the regulatory assets and regulatory liabilities summarized as 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.

	March 31,		December 31,
Millions of dollars	2006		2005
Regulatory Assets:
Under-collections - gas cost adjustment clause	$	15	$	5
Deferred environmental remediation costs		10		10
Asset retirement obligations		10		10
Other		1		1
Total Regulatory Assets	$	36	$	26

Regulatory Liabilities:
Over-collections - gas cost adjustment clause	$	24	$	20
Other asset removal costs		152		91
Other		3		3
Total Regulatory Liabilities	$	179	$	114

Under- ~~(over-) collections-gas~~and over-collections-gas cost adjustment ~~clause, net represents~~clauses represent 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~~$2.9 million. Management believes that these costs and the estimated remaining costs of ~~approximately $8.7~~$7.4 million will be recoverable.

Asset retirement obligations (AROs) represent the regulatory asset associated with conditional AROs recorded by SFAS 143, “Accounting for Asset Retirement Obligations,” and Financial Accounting Standards Board Interpretation (FIN) 47, “Accounting for Conditional Asset Retirement Obligations.”

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

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~~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 ~~$(0.4)~~$(0.2) million and ~~$(0.7)~~$(0.3) million as of ~~September 30, 2005~~March 31, 2006 and December 31, ~~2004,~~2005, respectively.

C.Transactions with Affiliates

The Company has related party transactions with its equity method investees. The Company records as cost of gas the storage and transportation costs charged by these investees. These costs totaled $3.9 million for the three months ended March 31, 2006 and 2005. The Company owed these investees $1.3 million at March 31, 2006 and December 31, 2005. The Company received cash distributions from equity investees of $1.3 million and $1.6 million for the three months ended March 31, 2006 and 2005, respectively.

During the three months ended March 31, 2006 and 2005, the Company had sales to an affiliate for natural gas and transportation services of $5.7 million and $10.6 million, respectively.

At March 31, 2006, an affiliate owed the Company $1.8 million for natural gas and transportation services. Additionally, the Company owed an affiliate $0.2 million related to billing and collection services for the sale of energy-related products and service contracts.

D. New Accounting ~~Matters~~Standards

~~Financial Accounting Standards Board Interpretation (FIN) 47,~~ SFAS 123 (revised 2004),“~~Accounting for Conditional Asset Retirement Obligations~~Share-Based Payment,”,” (SFAS 123(R)) was issued in ~~March 2005~~December 2004 and requires compensation costs related to ~~clarify the term “conditional asset retirement” as used in SFAS 143, “~~~~Accounting for Asset Retirement Obligations~~~~.” It requires that a liability~~share-based payment transactions to be recognized ~~for~~in the ~~fair value of a conditional asset retirement obligation when incurred, if~~financial statements. With limited exceptions, compensation cost is measured based on the grant-date fair value of the ~~liability can be reasonably estimated. Uncertainty about~~instruments issued and is recognized over the ~~timing or method of settlement of a conditional asset retirement obligation would be factored into~~period that an employee provides service in exchange for the ~~measurement~~award. SFAS 123(R) replaces SFAS 123, “Accounting for Stock-Based Compensation” and supersedes APB 25, “Accounting for Stock Issued to Employees.” The cumulative effect of the ~~liability when sufficient information exists, but such uncertainty would not be~~adoption of SFAS 123(R) on January 1, 2006 resulted in a ~~basis upon which to avoid liability recognition. This interpretation is effective no later than the end~~$0.7 million (net of ~~fiscal years ending after December 15, 2005. Accordingly, the Company will adopt FIN 47~~tax) gain in the ~~fourth~~first quarter of ~~2005. The impact FIN 47 may have~~2006 based on ~~the Company’s assets~~a reduction of prior compensation accruals for performance awards granted in 2004 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~~2005.

E. Reclassifications

Certain amounts from prior periods have been reclassified to conform with the presentation adopted for ~~2005.~~2006.

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~~2005 through ~~September 30, 2005~~March 31, 2006 was as follows:

Rate Per Therm Effective Date
$~~.600~~ ~~January-September 2004~~
~~$.675~~ ~~October-November 2004~~
$.825 ~~December 2004-January~~January 2005
$.725 February-July 2005
$.825 August-September 2005
$1.100 October 2005
$1.275 November-December 2005
$1.075 January 2006
$0.875 February 2006
$0.825 March 2006
On April 3, 2006, the Company filed an application with the NCUC requesting a 4.9 percent, or $28.4 million, increase in its base rates. The Company also requested a $7.5 million reduction in the fixed-cost portion of its cost of gas, resulting in an overall increase of 3.6 percent, or $20.9 million, in rates and charges for natural gas utility service. The rate increase is largely associated with recovering increased plant investment and operating costs. If approved, the new rates will be effective for the 2006-2007 winter season. A hearing is scheduled for August 2006.

61
~~Table of Contents~~
      ~~In September 2005~~On January 11, 2006, the NCUC approved the Company’s request to ~~increase the benchmark cost~~place all impacts to its results 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~~operation caused by the ~~North Carolina General Assembly~~adoption of FIN 47 in ~~1991~~regulatory deferred accounts. SFAS 143, together with FIN 47, provides guidance for recording and ~~funded by refunds~~disclosing liabilities related to future legally enforceable obligations to retire assets (ARO).
Refunds from the Company’s interstate pipeline transporters ~~provides~~are placed in a state-approved expansion fund and provide 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 state 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.~~2005.

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~~March 31, 2006, the Company had a deferred net realized gain of ~~approximately $3.7~~$8.1 million. In addition, as of ~~September 30, 2005~~March 31, 2006, the Company had unrealized ~~gains~~losses of ~~approximately $11~~$1.7 million, also recorded in other regulatory ~~liabilities.~~assets.

The Company also utilizes a swap agreement to manage interest rate risk. At ~~September 30, 2005~~March 31, 2006 the estimated fair value of the Company’s swap was ~~$0.7~~$0.1 million (gain) related to a notional amount of $22.4 million.

~~4.          DEBT AND CREDIT FACILITY~~

4. COMMITMENTS AND CONTINGENCIES

          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~~$7.4 million, which reflects its estimated remaining liability at ~~September 30, 2005.~~March 31, 2006. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through ~~gas~~ rates are ~~approximately $1.7~~$2.9 million. ~~Management believes that all MGP cleanup costs will~~Any cost arising from this matter is expected to be recoverable through ~~gas~~ rates.

62
~~Table of Contents~~

6.5.       SEGMENT OF BUSINESS INFORMATION

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

2005

2004

2006

2005

Operating

Net

Operating

Net

External

Income

Income

Segment

External

Income

Income

Segment

External

Operating

Net

Segment

External

Operating

Net

Segment

(Millions of dollars)

Revenue

(Loss)

(Loss)

Assets

Revenue

(Loss)

(Loss)

Assets

Revenue

Income

Income

Assets

Revenue

Income

Income

Assets

Three Months Ended September 30,

Three Months Ended March 31,

Gas Distribution $ 60 $ (4 ) $ (6 ) $ 53 $ (6 ) $ (6 ) $ 253 $ 40 n/a $ 1,120 $ 246 $ 43 n/a $ 1,055
All Other - n/a - - n/a - - n/a - 28 - n/a - 27
Adjustments/Eliminations - - - - - - - - $ 23 133 - - $ 24 66
Consolidated Total

$
60

$
(4
)
$
(6
)

$
53

$
(6
)
$
(6
)

$
253

$
40

$
23

$
1,281

$
246

$
43

$
24

$
1,148

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

63
~~Table of Contents~~

ITEM 2.   MANAGEMENT’S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

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.~~2005.

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~~three months ended ~~September 30, 2005 increased $4.0~~March 31, 2006 decreased $1.0 million compared to the same period in ~~2004,~~2005, primarily due to ~~increased~~decreased margin.

The nature of PSNC Energy’s business is seasonal. The quarters ending ~~June 30~~March 31 and ~~September 30~~December 31 are generally PSNC Energy’s ~~least~~most profitable quarters due to ~~decreased~~increased demand for natural gas related to space heating requirements.

PSNC Energy’s Board of Directors has authorized the following distributions/dividends on common stock held by SCANA during ~~2005:~~2006:

Declaration Date Amount Quarter Ended Payment Date
February ~~17, 2005~~16, 2006 $~~3.5~~3.9 million March 31, ~~2005~~2006 April 1, ~~2005~~2006
~~May 5, 2005~~April 27, 2006 $~~3.5~~3.9 million June 30, ~~2005~~2006 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,
Three Months Ended March 31,
Millions of dollars 2005 % Change 2004 2006 % Change 2005

Operating revenues $ 389.8 12.0 % $ 347.9 $ 253.0 2.9 % $ 245.9
Less: Gas purchased for resale 260.7 15.3 % 226.1 182.2 5.9 % 172.1
Margin $ 129.1 6.0 % $ 121.8 $ 70.8 (4.1 )% $ 73.8

64
Gas distribution sales margin ~~increased~~decreased primarily due to ~~increased residential~~lower customer ~~growth and increased consumption.~~

~~Other Income~~

~~Other income improved primarily~~usage, despite a 3.4 percent increase in customer growth. This decrease in consumption is attributable to conservation due to ~~the recognition of a $1 million loss in 2004 on the sale of PSNC Energy’s former corporate headquarters~~higher natural gas prices and due to ~~approximately $0.5 million in increased interest income on amounts under-collected from customers through the Rider D mechanism.~~milder weather.

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~~2006 construction budget is ~~approximately $58~~$71 million, compared to actual construction expenditures through ~~September 30, 2005~~March 31, 2006 of ~~approximately $43~~$17 million. PSNC Energy’s ratio of earnings to fixed charges for the 12 months ended ~~September 30, 2005~~March 31, 2006 was ~~3.23.~~2.85.

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.

65
~~Table of Contents~~

~~Item~~

ITEM 4. ~~Controls and Procedures~~CONTROLS AND PROCEDURES

As of ~~September 30, 2005~~March 31, 2006 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~~March 31, 2006 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~~March 31, 2006 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.

66
~~Table of Contents~~

PART II. OTHER INFORMATION

~~Item~~ITEM 1. ~~Legal Proceedings~~ 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~~2005 Annual Reports on Form 10-K have not changed ~~significantly unless noted below.~~significantly.
ITEM 6. EXHIBITS

~~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.
67
    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%~~10 percent 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.

68
~~Table of Contents~~

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~~thereunto 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/~~/s/James E. Swan, IV
~~November~~May 4, ~~2005~~2006 James E. Swan, IV
Controller
~~(Principal~~(Principal accounting officer)

69
~~Table of Contents~~

EXHIBIT INDEX

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

~~3.11~~3.12 X
Articles of Amendment dated March ~~9, 2005~~14, 2006, amending the Restated Articles of Incorporation of South Carolina Electric & Gas Company (Filed as Exhibit ~~3.11~~3.01 to Form ~~10-Q for the quarter ended~~
8-K dated 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)17, 2006)

3.13 X
Articles of Correction dated March 17, 2006, amending the Articles of Amendment dated ~~June 15, 2005 amending the Restated Articles of Incorporation~~March 14, 2006 of South Carolina Electric & Gas Company (Filed as Exhibit ~~3.13~~3.02 to Form ~~10-Q for the quarter ended June 30, 2005)~~8-K dated March 17, 2006)

~~3.14~~ 10.01 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 Corporation Director Compensation and Deferral Plan ~~adopted~~as
~~November 2,~~adopted December 20, 2005 (Filed herewith)

~~10.10~~ 10.02 X
Amendment to SCANA Corporation ~~Short-Term Annual Incentive~~Executive Deferred Compensation Plan as ~~amended and restated effective~~adopted
~~January 1,~~December 20, 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~~
(Furnished herewith)

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

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

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

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

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

70


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.

*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

*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

	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

	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

*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

	Nine Months Ended September 30,							Three Months Ended March 31,
Millions of dollars	2005		% Change			2004		2006		% Change			2005

Operating revenues	$	389.8		12.0	%	$	347.9	$	253.0		2.9	%	$	245.9
Less: Gas purchased for resale		260.7		15.3	%		226.1		182.2		5.9	%		172.1
Margin	$	129.1		6.0	%	$	121.8	$	70.8		(4.1	)%	$	73.8

By:	~~/s/~~/s/James E. Swan, IV
~~November~~May 4, ~~2005~~2006	James E. Swan, IV
	Controller
	~~(Principal~~(Principal accounting officer)

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

~~3.11~~3.12		X		Articles of Amendment dated March ~~9, 2005~~14, 2006, amending the Restated Articles of Incorporation of South Carolina Electric & Gas Company (Filed as Exhibit ~~3.11~~3.01 to Form ~~10-Q for the quarter ended~~ 8-K dated 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)17, 2006)
3.13		X		Articles of Correction dated March 17, 2006, amending the Articles of Amendment dated ~~June 15, 2005 amending the Restated Articles of Incorporation~~March 14, 2006 of South Carolina Electric & Gas Company (Filed as Exhibit ~~3.13~~3.02 to Form ~~10-Q for the quarter ended June 30, 2005)~~8-K dated March 17, 2006)
~~3.14~~ 10.01		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 Corporation Director Compensation and Deferral Plan ~~adopted~~as ~~November 2,~~adopted December 20, 2005 (Filed herewith)
~~10.10~~ 10.02	X			Amendment to SCANA Corporation ~~Short-Term Annual Incentive~~Executive Deferred Compensation Plan as ~~amended and restated effective~~adopted ~~January 1,~~December 20, 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~~ (Furnished herewith)
32.02	X			Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 ~~(Furnished~~ (Furnished herewith)
32.03		X		Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 ~~(Furnished~~ (Furnished herewith)
32.04		X		Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 ~~(Furnished~~ (Furnished herewith)
32.05			X	Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 ~~(Furnished~~ (Furnished herewith)
32.06			X	Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 ~~(Furnished~~ (Furnished herewith)