UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2005

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period from                     to 

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

	Description of	Shares Outstanding
Registrant	Common Stock	at July 31, 2005
SCANA Corporation	Without Par Value	114,042,772
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

PART I. FINANCIAL INFORMATION	Page
SCANA Corporation Financial Section	2
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004	3
Condensed Consolidated Statements of Income for the Periods Ended June 30, 2005 and 2004	5
Condensed Consolidated Statements of Cash Flows for the Periods Ended June 30, 2005 and 2004	6
Condensed Consolidated Statements of Comprehensive Income for the Periods  Ended June 30, 2005 and 2004	7
Notes to Condensed Consolidated Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3. Quantitative and Qualitative Disclosures About Market Risk	26
Item 4. Controls and Procedures	27
South Carolina Electric & Gas Company Financial Section	28
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004	29
Condensed Consolidated Statements of Income for the Periods Ended June 30, 2005 and 2004	31
Condensed Consolidated Statements of Cash Flows for the Periods Ended June 30, 2005 and 2004	32
Notes to Condensed Consolidated Financial Statements	33
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 3. Quantitative and Qualitative Disclosures About Market Risk	45
Item 4. Controls and Procedures	45
Public Service Company of North Carolina, Incorporated Financial Section	46
Item 1. Financial Statements  Condensed Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004	47
Condensed Consolidated Statements of Operations for the Periods Ended June 30, 2005 and 2004	49
Condensed Consolidated Statements of Cash Flows for the Periods Ended June 30, 2005 and 2004	50
Notes to Condensed Consolidated Financial Statements	51
Item 2. Management’s Narrative Analysis of Results of Operations	54
Item 4. Controls and Procedures	55
PART II. OTHER INFORMATION
Item 1. Legal Proceedings	56
Item 4. Submission of Matters to a Vote of Security Holders	57
Item 6. Exhibits	57
Signatures	58
Exhibit Index	59

1

2

PART I. FINANCIAL INFORMATION

SCANA CORPORATION

(Unaudited)

	June 30,			December 31,
Millions of dollars	2005			2004
Assets
Utility Plant In Service	$	8,753		$	8,373
Accumulated depreciation and amortization		(2,562	)		(2,315	)
		6,191			6,058
Construction work in progress		177			432
Nuclear fuel, net of accumulated amortization		38			42
Acquisition adjustments		230			230
Utility Plant, Net		6,636			6,762
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $57 and $50		103			104
Assets held in trust, net - nuclear decommissioning		52			49
Investments		60			63
Nonutility Property and Investments, Net		215			216
Current Assets:
Cash and cash equivalents		146			120
Receivables, net of allowance for uncollectible accounts of $23 and $16		544			687
Receivables - affiliated companies		23			19
Inventories (at average cost):
Fuel		177			191
Materials and supplies		73			70
Emission allowances		36			9
Prepayments and other		54			53
Total Current Assets		1,053			1,149
Deferred Debits:
Environmental		25			18
Pension asset, net		294			285
Other regulatory assets		378			402
Other		160			164
Total Deferred Debits		857			869
Total	$	8,761		$	8,996

3

	June 30,		December 31,
Millions of dollars	2005		2004
Capitalization and Liabilities
Shareholders’ Investment:
Common equity	$	2,560	$	2,451
Preferred stock (Not subject to purchase or sinking funds)		106		106
Total Shareholders’ Investment		2,666		2,557
Preferred Stock, net (Subject to purchase or sinking funds)		8		9
Long-Term Debt, net		3,072		3,186
Total Capitalization		5,746		5,752
Current Liabilities:
Short-term borrowings		446		211
Current portion of long-term debt		54		204
Accounts payable		227		381
Accounts payable - affiliated companies		23		18
Customer deposits		50		50
Taxes accrued		67		132
Interest accrued		52		51
Dividends declared		47		43
Other		92		100
Total Current Liabilities		1,058		1,190
Deferred Credits:
Deferred income taxes, net		859		879
Deferred investment tax credits		120		121
Asset retirement obligation - nuclear plant		128		124
Other asset retirement obligations		467		450
Postretirement benefits		145		142
Other regulatory liabilities		107		209
Other		131		129
Total Deferred Credits		1,957		2,054
Commitments and Contingencies (Note 6)		-		-
Total	$	8,761	$	8,996

  See Notes to Condensed Consolidated Financial Statements.

4

 SCANA CORPORATION

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Millions of dollars, except per share amounts	2005			2004			2005			2004
Operating Revenues:
Electric	$	438		$	434		$	853		$	814
Gas - regulated		219			188			680			614
Gas - nonregulated		234			224			624			547
Total Operating Revenues		891			846			2,157			1,975
Operating Expenses:
Fuel used in electric generation		137			120			265			215
Purchased power		11			20			18			33
Gas purchased for resale		376			335			1,037			906
Other operation and maintenance		153			144			312			298
Depreciation and amortization		89			66			334			129
Other taxes		40			38			78			77
Total Operating Expenses		806			723			2,044			1,658
Operating Income		85			123			113			317
Other Income (Expense):
Other income, including allowance for equity funds
used during construction of $3, $5, $6 and $10		13			16			25			30
Interest charges, net of allowance for borrowed funds
used during construction of $1, $3, $1 and $6		(54	)		(51	)		(108	)		(101	)
Gain on sale of investments and assets		8			1			8			1
Total Other Expense		(33	)		(34	)		(75	)		(70	)
Income Before Income Taxes, Earnings (Losses) from Equity
Method Investments and Preferred Stock Dividends		52			89			38			247
Income Tax Expense (Benefit)		3			28			(176	)		84
Income Before Earnings (Losses) from Equity Method
Investments and Preferred Stock Dividends		49			61			214			163
Earnings (Losses) from Equity Method Investments		(3	)		1			(65	)		2
Income Before Preferred Stock Dividends		46			62			149			165
Cash Dividends on Preferred Stock of Subsidiary		2			2			4			4
Net Income	$	44		$	60		$	145		$	161
Basic and Diluted Earnings Per Share of Common Stock	$	.39		$	.54		$	1.28		$	1.45
Weighted Average Shares Outstanding (millions)		113.6			111.2			113.3			111.0
See Notes to Condensed Consolidated Financial Statements.

5

SCANA CORPORATION

(Unaudited)

	Six Months Ended
	June 30,
Millions of dollars	2005			2004
Cash Flows From Operating Activities:
Net income	$	145		$	161
Adjustments to reconcile net income to net cash provided from operating activities:
Losses (earnings) from equity method investments		65			(2	)
Depreciation and amortization		342			134
Amortization of nuclear fuel		8			11
Gain on sale of assets and investments		(8	)		(1	)
Hedging activities		5			(3	)
Allowance for funds used during construction		(6	)		(10	)
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		139			78
Inventories		(36	)		(19	)
Prepayments and other		17			(9	)
Pension asset		(8	)		(7	)
Other regulatory assets		22			(25	)
Deferred income taxes, net		(29	)		34
Regulatory liabilities		(166	)		14
Postretirement benefits obligations		3			3
Accounts payable		(122	)		(23	)
Taxes accrued		(65	)		(42	)
Interest accrued		1			1
Changes in fuel adjustment clauses		10			44
Changes in other assets		6			(4	)
Changes in other liabilities		10			10
Net Cash Provided From Operating Activities		333			345
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(212	)		(253	)
Proceeds from sale of assets and investments		6			1
Nonutility property additions		(7	)		(3	)
Investments in affiliates and other		(27	)		(8	)
Net Cash Used For Investing Activities		(240	)		(263	)
Cash Flows From Financing Activities:
Proceeds from issuance of debt		197			124
Proceeds from issuance of common stock		47			22
Repayment of debt		(456	)		(4	)
Repurchase of common stock		-			(4	)
Redemption of preferred stock		(1	)		-
Dividends on equity securities		(89	)		(83	)
Short-term borrowings, net		235			(27	)
Net Cash (Used For) Provided From Financing Activities		(67	)		28
Net Increase In Cash and Cash Equivalents		26			110
Cash and Cash Equivalents, January 1		120			117
Cash and Cash Equivalents, June 30	$	146		$	227
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $1 and $6)	$	110		$	100
- Income taxes		45			21
Noncash Investing and Financing Activities:
Unrealized loss on securities available for sale, net of tax		-			(12	)
Accrued construction expenditures		14			18

See Notes to Condensed Consolidated Financial Statements.

6

SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
Millions of dollars	2005			2004			2005		2004
Net Income	$	44		$	60		$	145	$	161
Other Comprehensive Income (Loss), net of tax:
Unrealized losses on securities available for sale		-			(6	)		-		(12	)
Unrealized gains (losses) on hedging activities		(3	)		-			4		(2	)
Total Comprehensive Income (1)	$	41		$	54		$	149	$	147
(1) Accumulated other comprehensive income (loss) totaled $0.4 million and $(3.8) million as of June 30, 2005 and December 31, 2004, respectively.
See Notes to Condensed Consolidated Financial Statements.

7

SCANA CORPORATION

June 30, 2005

(Unaudited)

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

1.       SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.      Basis of Accounting

The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS 71 requires cost-based rate-regulated utilities to recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, as of June 30, 2005 the Company has recorded approximately $403 million and $574 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.

	June 30,			December 31,
Millions of dollars	2005			2004
Accumulated deferred income taxes, net	$	127		$	126
Under-collections - electric fuel and gas cost adjustment clauses, net		13			41
Deferred purchased power costs		21			26
Deferred environmental remediation costs		25			18
Asset retirement obligation - nuclear decommissioning		51			49
Other asset retirement obligations		(467	)		(450	)
Deferred synthetic fuel tax benefits, net		-			(97	)
Storm damage reserve		(35	)		(33	)
Franchise agreements		56			58
Deferred regional transmission organization costs		12			14
Other		26			19
Total	$	(171	)	$	(229	)

Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.

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

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

Deferred environmental remediation costs represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by the Company. Costs incurred at sites owned by SCE&G are being recovered through rates, of which approximately $13.6 million remain. 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 through rates are approximately $2.4 million. Management believes that these costs and the remaining costs of approximately $8.8 million will be recoverable.

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

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

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

8

   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 six months ended June 30, 2005, no significant amounts have been drawn from this reserve account.

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

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

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

B.      Equity Compensation Plan

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

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

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
Net income - as reported (millions)	$44	$60	$145	$161
Net income - pro forma (millions)	$44	$60	$145	$161
Basic and diluted earnings per share - as reported	$.39	$.54	$1.28	$1.45
Basic and diluted earnings per share - pro forma	$.39	$.54	$1.28	$1.45

 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 $2.9 million and $4.8 million for the three and six months ended June 30, 2005, respectively, and approximately $2.5 million and $4.8 million for the corresponding periods ended June 30, 2004, respectively.

9

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 June 30
Service cost	$	3.1		$	2.8		$	0.9	$	0.8
Interest cost		9.5			9.6			2.8		2.9
Expected return on assets		(19.1	)		(17.8	)		-		-
Prior service cost amortization		1.7			1.6			0.3		0.2
Transition obligation amortization		0.2			0.2			0.2		0.2
Amortization of actuarial loss		-			-			0.4		0.5
Net periodic benefit (income) cost	$	(4.6	)	$	(3.6	)	$	4.6	$	4.6

Six months ended June 30
Service cost	$	6.1		$	5.6		$	1.8	$	1.6
Interest cost		19.0			18.7			5.6		5.8
Expected return on assets		(38.2	)		(35.5	)		-		-
Prior service cost amortization		3.4			3.2			0.6		0.4
Transition obligation amortization		0.4			0.4			0.4		0.4
Amortization of actuarial loss		-			-			0.8		1.0
Net periodic benefit (income) cost	$	(9.3	)	$	(7.6	)	$	9.2	$	9.2

D.      Earnings Per Share

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

E.      Transactions with Affiliates

SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel. SCE&G had recorded as receivables from these affiliated companies approximately $23.0 million and $18.6 million at June 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 June 30, 2005 and December 31, 2004, respectively. SCE&G purchased approximately $62.8 million and $51.5 million of synthetic fuel from these affiliated companies for the three months ended June 30, 2005 and 2004, respectively. SCE&G purchased approximately $113.7 million and $90.2 million of synthetic fuel from these affiliated companies for the six months ended June 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 prior periods’ financial statements of every voluntary change in accounting principle unless it is impracticable. SFAS 154 replaces Accounting Principles Board (APB) Opinion 20, “Accounting Changes,” and SFAS 3, “Reporting Accounting Changes in Interim Financial Statements,” although it carries forward some of their provisions. The Company will adopt SFAS 154 in the first quarter of 2006, and does not expect that the initial adoption will have a material impact on the Company’s results of operations, cash flows or financial position.

 Financial Accounting Standards Board Interpretation (FIN) 47, “Accounting for Conditional Asset Retirement Obligations,” was issued in March 2005 to clarify the term “conditional asset retirement” as used in SFAS 143, “Accounting for Asset Retirement Obligations.” It requires that a liability be recognized for the fair value of a conditional asset retirement obligation when incurred, if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation would be factored into the measurement of the liability when sufficient information exists. 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. 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.

10

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

G.      Reclassifications

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

2.       RATE AND OTHER REGULATORY MATTERS

   South Carolina Electric & Gas Company (SCE&G)

Electric

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

In the January 2005 order the SCPSC also approved recovery over a five-year period of SCE&G's approximately $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization and recovery through base rates over three years of approximately $25.6 million of purchased power costs that were previously deferred. As a part of its order, the SCPSC extended through 2010 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station up to $36 million annually without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.

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

Rate Per KWh	Effective Date
$.01678	January-April 2004
$.01821	May-December 2004
$.01764	January-April 2005
$.02256	May 2005-June 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 June 30, 2005 was as follows:

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

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

11

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

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

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

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

 On August 1, 2005 the NCUC approved PSNC Energy's request to increase the benchmark cost of gas from $.725 per therm to $.825 per therm for service rendered on and after August 1, 2005.

     On June 1, 2005 PSNC Energy filed testimony in the 2005 Annual Prudence Review related to the 12 months ended March 31, 2005. The NCUC will hold a hearing in August 2005 to consider the filing.

A state expansion fund, established by the North Carolina General Assembly in 1991 and funded by refunds from PSNC Energy’s interstate pipeline transporters, provides financing for expansion into areas that otherwise would not be economically feasible to serve. On May 12, 2005 PSNC Energy filed an application with the NCUC to extend natural gas service to Louisburg, North Carolina, and requested authorization to withdraw up to approximately $1.2 million from its expansion fund for this project. The NCUC will hold a hearing in August 2005 to consider the filing.

In March 2005 PSNC Energy refunded approximately $7.7 million in pipeline supplier refunds by a direct bill credit to various customers. This refund resulted in a reduction in restricted cash and the associated current liability.

On January 21, 2005 the NCUC authorized PSNC Energy to defer for subsequent rate consideration certain expenses incurred to comply with the U. S. Department of Transportation’s Pipeline Integrity Management requirements. This accounting treatment was effective November 1, 2004. As of June 30, 2005 such deferrals totaled $0.3 million.

   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 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 were 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 financial position, results of operations or cash flows.

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 June 30, 2005, of SCE&G’s approximately $934 million in retained earnings, approximately $50 million were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.

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5.       FINANCIAL INSTRUMENTS

The Company follows the guidance required by FAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, in accounting for derivatives, including those arising from cash flow hedges related to natural gas. The Company also utilizes swap agreements to manage interest rate risk. These transactions are more fully described in Note 9 to the consolidated financial statements in SCANA’s Annual Report on Form 10-K for the year ended December 31, 2004.

The Company recognizes gains (losses) as a result of qualifying cash flow hedges whose hedged transactions occur during the reporting period and records them, net of taxes, in cost of gas. The Company recognized a gain of $0.5 million and a loss of $(2.7) million for the three and six months ended June 30, 2005, respectively, and recognized gains of $1.2 million and $3.0 million for the corresponding periods ended June 30, 2004, respectively. The Company estimates that most of the June 30, 2005 unrealized gain balance of $1.1 million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in 2005 and 2006 as a decrease to gas cost if market prices remain at current levels. As of June 30, 2005, all of the Company's cash flow hedges settle by their terms before the end of March 2007.

At June 30, 2005 the estimated fair value of the Company’s swaps totaled $0.9 million (gain) related to combined notional amounts of $47.4 million.

6.    COMMITMENTS AND CONTINGENCIES

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

A.    Nuclear Insurance

The Price-Anderson Indemnification Act (the Act) deals with public liability for a nuclear incident. Though the Act expired in 2003, existing licensees, such as the Company, are “grandfathered” under the Act until such time as it is renewed. The Act establishes the liability limit for third party claims associated with any nuclear incident at $10.5 billion. Each reactor licensee is currently liable for up to $100.6 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $10 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station, would be approximately $67.1 million per incident, but not more than $6.7 million per year.

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

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

B.    Environmental

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

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

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 $13.6 million at June 30, 2005. The deferral includes the estimated costs associated with the following matters.

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    SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for contamination. SCE&G anticipates that the remaining remediation activities will be completed by the end of 2005, with certain monitoring and retreatment activities continuing until 2010. As of June 30, 2005, SCE&G had spent approximately $20.9 million to remediate the Calhoun Park site and expects to spend an additional $1.0 million. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of approximately $9 million for certain costs and damages relating to this site. Any costs arising from these matters are expected to be recoverable through rates under South Carolina regulatory process.

      SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. One of the sites has been remediated and will undergo routine monitoring until released by the South Carolina Department of Health and Environmental Control (DHEC). The other sites are currently being investigated under work plans approved by DHEC. SCE&G anticipates that major remediation activities for the three sites will be completed in 2010. As of June 30, 2005, SCE&G had spent approximately $4.2 million related to these three sites, and expects to spend an additional $8.3 million.

  Public Service Company of North Carolina, Incorporated

 PSNC Energy is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy’s actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other potentially responsible parties. The Company has recorded a liability and associated regulatory asset of approximately $8.8 million, which reflects its estimated remaining liability at June 30, 2005. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates are approximately $2.4 million. Management believes that all MGP cleanup costs will be recoverable through gas rates.

C.      Claims and Litigation

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

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

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

The Company is also defending another 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 these propane gas assets. A bench trial on the indemnification was held on January 14, 2005; however, a ruling has not been received. The Company 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. The plaintiffs are seeking damages for the alleged improper use of electric transmission and distribution easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to non-utility third parties or telecommunication companies for other than the electric utilities' internal use along the electric transmission and distribution line rights-of-way constitutes a trespass. The Company is confident of the propriety of SCE&G’s actions and intends to mount a vigorous defense. The Company further believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.

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

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

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

7. SEGMENT OF BUSINESS INFORMATION

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

							Operating			Net
Millions of dollars	External Revenue			Intersegment Revenue			Income (Loss)			Income (Loss)		Segment Assets
Three Months Ended June 30, 2005
Electric Operations	$	438		$	1		$	83			n/a
Gas Distribution		168			-			(5	)		n/a
Gas Transmission		51			71			5			n/a
Retail Gas Marketing		92			-			n/a		$	1
Energy Marketing		142			24			n/a			-
All Other		18			81			n/a			1
Adjustments/Eliminations		(18	)		(177	)		2			42
Consolidated Total	$	891		$	-		$	85		$	44

Six Months Ended June 30, 2005
Electric Operations	$	853		$	2		$	8		n/a		$	5,287
Gas Distribution		572			-			55		n/a			1,484
Gas Transmission		108			195			12		n/a			291
Retail Gas Marketing		331			-			n/a	$	23			119
Energy Marketing		293			43			n/a		(1	)		67
All Other		34			155			n/a		(62	)		365
Adjustments/Eliminations		(34	)		(395	)		38		185			1,148
Consolidated Total	$	2,157		$	-		$	113	$	145		$	8,761

Three Months Ended June 30, 2004
Electric Operations	$	434		$	1		$	120			n/a
Gas Distribution		137			-			(9	)		n/a
Gas Transmission		51			63			5			n/a
Retail Gas Marketing		91			-			n/a		$	3
Energy Marketing		133			23			n/a			(1	)
All Other		18			72			n/a			3
Adjustments/Eliminations		(18	)		(159	)		7			55
Consolidated Total	$	846		$	-		$	123		$	60

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Six Months Ended June 30, 2004
Electric Operations	$	814		$	2		$	217		n/a		$	5,169
Gas Distribution		509			-			49		n/a			1,412
Gas Transmission		105			181			11		n/a			323
Retail Gas Marketing		309			-			n/a	$	23			106
Energy Marketing		238			26			n/a		(1	)		73
All Other		33			142			n/a		5			641
Adjustments/Eliminations		(33	)		(351	)		40		134			887
Consolidated Total	$	1,975		$	-		$	317	$	161		$	8,611

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

SCANA CORPORATION

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

Electric Operations

  The Energy Policy Act of 2005 (the “energy bill”) passed both houses of Congress in July 2005 and is expected to be signed by the President in August 2005.   Some 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.  Also, the energy bill repeals the Public Utility Holding Company Act of 1935, and provides for greater regulatory oversight by other federal and state authorities.  The Company is reviewing the energy bill to determine the impact it will 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

On April 26, 2005, SCE&G filed an application with the Public Service Commission of South Carolina (SCPSC) requesting a 7.09 percent increase in retail natural gas base rates, or approximately $28 million based on an adjusted test year ended December 31, 2004. A hearing on this request is expected to be held in September 2005. If approved, it is anticipated that the new rates would go into effect in November 2005.

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

Gas Transmission

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 an agreement with them prior to filing the application with FERC. SCANA does not expect to receive approval for the merger from FERC before the summer of 2006.

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Retail Gas Marketing

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

  SCANA Energy has maintained a long-standing agreement with Cobb Energy Management Corporation (Cobb Energy), an affiliate of Cobb Electric Membership Corporation (Cobb EMC) under the terms of which the parties work in an exclusive relationship to attract and retain customers for SCANA Energy.  In July 2005, Southern Company Gas, the natural gas marketing affiliate of Southern Company, announced that Cobb EMC is preparing to seek certification from the GPSC to become a licensed natural gas marketer and that Southern Company Gas had signed a letter of intent to negotiate the sale of its business to a soon to be formed affiliate of Cobb EMC.  SCANA Energy believes that such efforts to enter the Georgia natural gas market are not consistent with our agreement and could affect the competitive market.  SCANA Energy is evaluating the prospects of the above announcement and is addressing this issue with Cobb Energy and Cobb EMC.   

RESULTS OF OPERATIONS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2005

AS COMPARED TO THE CORRESPONDING PERIODS IN 2004

Earnings Per Share

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

	Second Quarter				Year to Date
	2005		2004		2005		2004
Reported (GAAP) earnings per share	$	.39	$	.54	$	1.28	$	1.45
Less realized gain from sale of telecommunications investment		.03		-		.03		-
GAAP-adjusted net earnings from operations per share	$	.36	$	.54	$	1.25	$	1.45

Discussion of adjustment:

The realized gain on telecommunications investment resulted from the receipt of additional proceeds from the prior sale of the Company’s investment in ITC Holding Company in 2003. These additional proceeds had been held in escrow pending resolution of certain contingencies.

Second Quarter

GAAP-adjusted net earnings from operations per share decreased primarily due to unfavorable electric margins of $.03 (primarily caused by unfavorable weather), increased depreciation and amortization expense of $.05 (net of income tax benefits applied based on the January 2005 SCPSC order described below), increased operations and maintenance expenses of $.05, increased interest expense of $.01, increased property taxes of $.01 and the effects of dilution of $.01. 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.

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Year to Date

GAAP-adjusted net earnings from operations per share decreased primarily due to increased depreciation and amortization expense of $.12 (net of income tax benefits applied based on the January 2005 SCPSC order described below), increased operations and maintenance expenses of $.08, increased interest expense of $.04 and the effects of dilution of $.03, partially offset by favorable electric margins of $.02 and favorable gas margins of $.07. Accelerated depreciation on the Lake Murray back-up dam and recognition of synthetic fuel tax credits and related items had no effect on net income, as discussed below.

Recognition of Synthetic Fuel Tax Credits

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

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

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

	Recognized
Factors Increasing (Decreasing)	2nd Quarter			Year to Date
Net Income (millions)	2005			2005
Recognized in Statement of Income:
Depreciation and amortization expense	$	(13.9	)	$	(183.6	)
Income tax benefits:
From synthetic fuel tax credits		11.2			155.2
From accelerated depreciation		5.3			70.2
From partnership losses		1.6			25.9
Total income tax benefits		18.1			251.3
Losses from Equity Method Investments		(4.2	)		(67.7	)
Impact on Net Income		-			-

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Pension Income

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

	Second Quarter				Year to Date
Millions of dollars	2005		2004		2005		2004
Income Statement Impact:
Reduction in employee benefit costs	$	1.2	$	0.8	$	2.3	$	1.8
Other income		3.0		2.5		6.0		4.9
Balance Sheet Impact:
Reduction in capital expenditures		0.3		0.2		0.7		0.6
Component of amount due to Summer Station co-owner		0.1		0.1		0.3		0.3
Total Pension Income	$	4.6	$	3.6	$	9.3	$	7.6

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

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 and six months ended June 30, 2005 decreased primarily due to completion of the Jasper County Electric Generating Station in May 2004. Included in the equity portion of AFC for the three and six months ended June 30, 2005 is approximately $2.8 million and $5.6 million, respectively, which was accrued as a result of the January 2005 SCPSC rate order related to construction costs for the back-up dam at Lake Murray.

Dividends Declared

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

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

Electric Operations

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

	Second Quarter							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004
Operating revenues	$	437.6		0.7	%	$	434.5	$	852.9		4.7	%	$	814.4
Less: Fuel used in generation		137.2		14.2	%		120.1		265.0		23.0	%		215.5
Purchased power		11.0		(44.4	)%		19.8		17.6		(45.8	)%		32.5
Margin	$	289.4		(1.8	)%	$	294.6	$	570.3		0.7	%	$	566.4

Second Quarter

Margin decreased primarily due to unfavorable weather, which had an impact of $19.8 million. This decrease was offset by $9.7 million due to increased retail electric rates that went into effect in January 2005, by $2.6 million related to increased off-system sales and by customer growth and increased consumption of $2.0 million.

20

Year to Date

Margin increased primarily due to increased retail electric rates that went into effect in January 2005, which had an impact of $19.3 million, by $2.6 million related to increased off-system sales and by customer growth and increased consumption of $7.4 million. These factors were partially offset by $25.2 million due to unfavorable weather.

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:

	Second Quarter							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004
Operating revenues	$	168.6		22.8	%	$	137.3	$	571.4		12.3	%	$	509.0
Less: Gas purchased for resale		124.1		26.9	%		97.8		417.0		15.2	%		362.0
Margin	$	44.5		12.7	%	$	39.5	$	154.4		5.0	%	$	147.0

Second Quarter

Margin increased primarily due to customer growth and increased consumption.

Year to Date

Margin increased primarily due to customer growth and increased consumption of $8.1 million, partially offset by lower transportation revenue.

Gas Transmission

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

	Second Quarter							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004
Operating revenues	$	121.9		7.0	%	$	113.9	$	302.9		5.8	%	$	286.2
Less: Gas purchased for resale		109.9		9.2	%		100.6		275.8		6.8	%		258.3
Margin	$	12.0		(9.8	)%	$	13.3	$	27.1		(2.9	)%	$	27.9

Second Quarter

Margin decreased due to lower sales volumes to industrial interruptible customers.

Year to Date

Margin decreased slightly due to lower sales volumes to industrial interruptible customers offset by higher transportation volumes.

Retail Gas Marketing

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

	Second Quarter							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004
Operating revenues	$	91.9		0.8	%	$	91.2	$	330.8		7.1	%	$	308.9
Net income	$	1.0		(68.8	)%	$	3.2	$	23.4		(1.3	)%	$	23.7

21

Second Quarter

Operating revenues increased slightly primarily as a result of higher average retail prices due to higher commodity gas costs. Net income decreased primarily due to lower sales margins and higher operating and customer service expenses.

Year to Date

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

Energy Marketing

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

	Second Quarter									Year to Date
Millions of dollars	2005			% Change			2004			2005			% Change			2004
Operating revenues	$	166.5			4.5	%	$	159.3		$	337.0			22.8	%	$	274.5
Net loss	$	(0.2	)		*		$	(0.5	)	$	(1.1	)		*		$	(1.0	)

* Not meaningful

Second Quarter

Operating revenues increased primarily as a result of higher commodity prices which more than offset decreased volumes. Net loss decreased primarily due to decreased operating expenses.

Year to Date

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

Other Operating Expenses

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

	Second Quarter							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004
Other operation and maintenance	$	152.0		6.0	%	$	143.4	$	311.0		4.4	%	$297.8
Depreciation and amortization		89.0		*			66.6		333.8		*		129.3
Other taxes		40.0		4.2	%		38.4		78.0		1.0	%	77.2
Total	$	281.0		*		$	248.4	$	722.8		*		$504.3

* Not meaningful

Second Quarter

Other operation and maintenance expenses increased primarily due to increased nuclear and fossil maintenance expenses of $6.8 million. Depreciation and amortization increased approximately $13.9 million due to accelerated depreciation of the back-up dam at Lake Murray (previously explained at Recognition of Synthetic Fuel Tax Credits) and increased $2.7 million due to the completion of the Jasper County Electric Generating Station in May 2004 and $1.4 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 $4.4 million of additional depreciation expense in the period.

22

    Year to Date

Other operation and maintenance expenses increased primarily due to increased nuclear and fossil maintenance expenses of $11.4 million, partially offset by decreases in storm expenses of $1.9 million and $1.9 million of employee benefit expenses. Depreciation and amortization increased approximately $183.6 million due to accelerated depreciation of the back-up dam at Lake Murray (previously explained at Recognition of Synthetic Fuel Tax Credits) and increased $8.7 million due to the completion of the Jasper County Electric Generating Station in May 2004 and $2.9 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 $8.7 million of additional depreciation expense in the period.

Income Taxes

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

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its contractual cash obligations will be met through internally generated funds, the incurrence of additional short-term and long-term indebtedness and sales of additional equity securities. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future. The Company’s ratio of earnings to fixed charges for the 12 months ended June 30, 2005 was 1.75.

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

In a January 2005 order, the SCPSC granted SCE&G a composite increase in retail electric rates of approximately 2.89%, designed to produce additional annual revenues of approximately $41.4 million based on a test year calculation. The SCPSC lowered SCE&G's return on common equity from 12.45% to an amount not to exceed 11.4%, with rates set at 10.7%. The new rates became effective in January 2005. As part of its order, the SCPSC approved SCE&G's recovery of construction and operating costs for SCE&G's new Jasper County Electric Generating Station, recovery of costs of mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray (as previously discussed 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 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.

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

	Six Months Ended
	June 30,
Millions of dollars	2005			2004
Net cash provided from operating activities	$	333		$	345
Net cash (used for) provided from financing activities		(67	)		28
Cash provided from sale of investments and assets		6			1
Cash and cash equivalents available at the beginning of the period		120			117
Funds used for utility property additions and construction expenditures	$	(212	)	$	(253	)
Funds used for nonutility property additions		(7	)		(3	)
Funds used for investments		(27	)		(8	)

23

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

CAPITAL TRANSACTIONS

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

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

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 financial position, results of operations or cash flows.

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

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

CAPITAL PROJECTS

In May 2005 SCE&G substantially completed construction of a back-up dam at Lake Murray in order to comply with new federal safety standards mandated by FERC. Construction of the project and related activities are estimated to 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 oxides and sulfur dioxide emissions in order to attain mandated state levels. SCE&G has petitioned the United States Court of Appeals for the District of Columbia Circuit to review CAIR. Several other electric utilities have filed separate petitions. The petitioners seek a change in the method CAIR uses to allocate sulfur dioxide emission allowances to a method the petitioners believe is more equitable. The Company believes that installation of additional air quality controls will be needed to meet the CAIR requirements. Compliance plans and cost to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates.

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

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

24

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 June 30, 2005 is approximately $2.8 million, and through June 30, 2005, they have generated and passed through to SCE&G approximately $155.2 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 are recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation is recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

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

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

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

25

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

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

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

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 June 30, 2005			Expected Maturity Date
Millions of dollars
						There-		Fair
Liabilities	2005	2006	2007	2008	2009	After	Total	Value
Long-Term Debt:
Fixed Rate ($)	5.0	174.4	68.6	158.6	143.6	2,532.8	3,083.0	3,404.5
Average Fixed Interest Rate (%)	7.51	8.50	6.96	8.12	8.21	6.15	6.50	n/a
Variable Rate ($)				100.0			100.0	100.0
Average Variable Interest Rate (%)				3.48			3.48
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)	-	3.2	28.2	3.2	3.2	9.6	47.4	0.9
Average Pay Interest Rate (%)	-	6.63	6.94	6.63	6.63	6.63	6.81	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 realized loss will occur.

26

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
2005	Long ($)	Short ($)		(Long) ($)
Settlement Price (a)	7.16	7.09
Contract Amount	26.6	14.6	Strike Price (a)	7.42
Fair Value	28.1	14.4	Contract Amount	29.7
2006
Settlement Price (a)	8.40	8.61
Contract Amount	4.2	1.7	Strike Price (a)	8.41
Fair Value	5.0	1.7	Contract Amount	8.1
(a) Weighted average

Swaps
	2005	2006	2007
Pay fixed/receive variable ($)	9.4	7.9	0.7
Average pay interest rate (%) (a)	7.12	7.44	7.10
Average received interest rate (%) (a)	7.46	8.27	8.10
Pay variable/receive variable ($)	15.5	-	-
Average pay interest rate (%) (a)	7.16	-	-
Average received interest rate (%) (a)	7.14	-	-
(a) Weighted average

As of June 30, 2005 an evaluation was performed under the supervision and with the participation of the Company’s management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based on that evaluation, the Company’s management, including the CEO and CFO, concluded that as of June 30, 2005 the Company’s disclosure controls and procedures were effective. There has been no change in the Company’s internal control over financial reporting during the quarter ended June 30, 2005 that has materially affected or is reasonably likely to materially affect the Company’s internal control over financial reporting.

27

28

Item 1. Financial Statements

SOUTH CAROLINA ELECTRIC & GAS COMPANY

(Unaudited)

	June 30,			December 31,
Millions of dollars	2005			2004
Assets
Utility Plant In Service	$	7,483		$	7,096
Accumulated depreciation and amortization		(2,172	)		(1,934	)
		5,311			5,162
Construction work in progress		157			417
Nuclear fuel, net of accumulated amortization		38			42
Utility Plant, Net		5,506			5,621
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation		26			27
Assets held in trust, net - nuclear decommissioning		52			49
Investments		6			6
Nonutility Property and Investments, Net		84			82
Current Assets:
Cash and cash equivalents		17			20
Receivables, net of allowance for uncollected accounts of $2 and $1		306			267
Receivables - affiliated companies		33			19
Inventories (at average cost):
Fuel		62			35
Materials and supplies		66			64
Emission allowances		36			9
Prepayments and other		26			30
Total Current Assets		546			444
Deferred Debits:
Environmental		14			11
Pension asset, net		294			285
Due from affiliates - pension and postretirement benefits		23			23
Other regulatory assets		367			376
Other		138			138
Total Deferred Debits		836			833
Total	$	6,972		$	6,980

29

	June 30,		December 31,
Millions of dollars	2005		2004
Capitalization and Liabilities
Shareholders’ Investment:
Common equity	$	2,238	$	2,164
Preferred stock (Not subject to purchase or sinking funds)		106		106
Total Shareholders’ Investment		2,344		2,270
Preferred Stock, net (Subject to purchase or sinking funds)		8		9
Long-Term Debt, net		1,975		1,981
Total Capitalization		4,327		4,260
Minority Interest		81		81
Current Liabilities:
Short-term borrowings		446		153
Current portion of long-term debt		48		198
Accounts payable		77		106
Accounts payable - affiliated companies		94		113
Customer deposits		27		26
Taxes accrued		87		152
Interest accrued		34		35
Dividends declared		40		38
Other		50		50
Total Current Liabilities		903		871
Deferred Credits:
Deferred income taxes, net		721		744
Deferred investment tax credits		119		119
Asset retirement obligation - nuclear plant		128		124
Other asset retirement obligations		376		363
Due to affiliates - pension and postretirement benefits		13		14
Postretirement benefits		145		142
Other regulatory liabilities		91		198
Other		68		64
Total Deferred Credits		1,661		1,768
Commitments and Contingencies (Note 5)		-		-
Total	$	6,972	$	6,980

See Notes to Condensed Consolidated Financial Statements.

30

SOUTH CAROLINA ELECTRIC & GAS COMPANY

(Unaudited)

	Three Months Ended							Six Months Ended
	June 30,							June 30,
Millions of dollars		2005			2004			2005			2004
Operating Revenues:
Electric		$	438		$	435		$	854		$	817
Gas			85			68			242			213
Total Operating Revenues			523			503			1,096			1,030
Operating Expenses:
Fuel used in electric generation			137			120			265			215
Purchased power			11			20			17			33
Gas purchased for resale			71			55			192			166
Other operation and maintenance			112			104			221			212
Depreciation and amortization			78			55			311			107
Other taxes			36			35			71			70
Total Operating Expenses			445			389			1,077			803
Operating Income			78			114			19			227
Other Income (Expense):
Other Income, including allowance for equity funds
used during construction of $3, $4, $5 and $9			7			7			13			14
Interest charges, net of allowance for borrowed funds
used during construction of $1, $3, $1 and $6			(37	)		(35	)		(74	)		(70	)
Gain on sale of assets			1			1			1			2
Total Other Expense			(29	)		(27	)		(60	)		(54	)
Income (Loss) Before Income Taxes, Losses from Equity Method
Investments, Minority Interest and Preferred Stock Dividends			49			87			(41	)		173
Income Tax Expense (Benefit)			3			29			(205	)		58
Income Before Losses from Equity Method Investments,
Minority Interest and Preferred Stock Dividends			46			58			164			115
Losses from Equity Method Investments			(5	)		-			(69	)		(1	)
Minority Interest			1			1			3			3
Net Income			40			57			92			111
Preferred Stock Cash Dividends Declared			2			2			4			4
Earnings Available for Common Shareholder		$	38		$	55		$	88		$	107
See Notes to Condensed Consolidated Financial Statements.

31

SOUTH CAROLINA ELECTRIC & GAS COMPANY

(Unaudited)

	Six Months Ended
	June 30,
Millions of dollars	2005			2004
Cash Flows From Operating Activities:
Net income	$	92		$	111
Adjustments to reconcile net income to net cash provided from operating activities:
Losses from equity method investments		69			1
Minority interest		3			3
Depreciation and amortization		310			107
Amortization of nuclear fuel		8			11
Allowance for funds used during construction		(5	)		(9	)
Gain on sale of assets		(1	)		(2	)
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		(53	)		(25	)
Inventories		(75	)		(26	)
Prepayments		4			(29	)
Pension asset		(9	)		(8	)
Other regulatory assets		23			(24	)
Deferred income taxes, net		(38	)		31
Regulatory liabilities		(144	)		14
Postretirement benefits obligations		3			3
Accounts payable		(24	)		13
Taxes accrued		(65	)		(49	)
Interest accrued		(1	)		1
Changes in fuel adjustment clauses		(9	)		40
Changes in other assets		(6	)		(8	)
Changes in other liabilities		(9	)		10
Net Cash Provided From Operating Activities		73			165
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(183	)		(232	)
Proceeds from sale of assets		1			1
Investments in affiliates		(9	)		(8	)
Net Cash Used For Investing Activities		(191	)		(239	)
Cash Flows From Financing Activities:
Proceeds from issuance of debt		97			124
Repayment of debt		(253	)		-
Redemption of preferred stock		(1	)		-
Dividends on equity securities		(78	)		(80	)
Distribution to parent		-			(28	)
Contribution from parent		59			-
Short-term borrowings from affiliate, net		(2	)		(7	)
Short-term borrowings, net		293			28
Net Cash Provided From Financing Activities		115			37
Net Decrease In Cash and Cash Equivalents		(3	)		(37	)
Cash and Cash Equivalents, January 1		20			56
Cash and Cash Equivalents, June 30	$	17		$	19
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $1 and $6)	$	71		$	70
- Income taxes		23			33
Noncash Investing and Financing Activities:
Accrued construction expenditures		13			17
See Notes to Condensed Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

June 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 $81 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 June 30, 2005 the Company has recorded approximately $381 million and $467 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.

	June 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		22			31
Deferred purchased power costs		21			26
Deferred environmental remediation costs		14			11
Asset retirement obligation - nuclear decommissioning		51			49
Other asset retirement obligations		(376	)		(363	)
Deferred synthetic fuel tax benefits, net		-			(97	)
Storm damage reserve		(35	)		(33	)
Franchise agreements		56			58
Deferred regional transmission organization costs		12			14
Other		27			19
Total	$	(86	)	$	(164	)

  Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.

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

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

Deferred environmental remediation costs represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by SCE&G. Costs incurred by SCE&G at such sites are being recovered through rates, of which approximately $13.6 million remain.

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

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

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

The storm damage reserve represents an SCPSC approved reserve account 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 six months ended June 30, 2005, no significant amounts have been drawn from this reserve account.

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

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

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

C.      Transactions with Affiliates

SCE&G has entered into agreements with certain affiliates to purchase all gas for resale to its distribution customers and to purchase electric energy. SCE&G purchases natural gas for resale and for electric generation from South Carolina Pipeline Corporation (SCPC) and had approximately $20.7 million and $49.5 million payable to SCPC for such gas purchases at June 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 $23.0 million and $18.6 million at June 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 June 30, 2005 and December 31, 2004, respectively. SCE&G purchased approximately $62.8 million and $51.5 million of synthetic fuel from these affiliated companies for the three months ended June 30, 2005 and 2004, respectively. SCE&G purchased approximately $113.7 million and $90.2 million of synthetic fuel from these affiliated companies for the six months ended June 30, 2005 and 2004, respectively.

In the six months ended June 30, 2005, the Company purchased approximately 342 miles of gas distribution pipeline from SCPC at it’s net book value, which totaled approximately $20.8 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 June 30
Service cost	$	3.1		$	2.8		$	0.9		$	0.8
Interest cost		9.5			9.6			2.8			2.9
Expected return on assets		(19.1	)		(17.8	)		-			-
Prior service cost amortization		1.7			1.6			0.3			0.2
Transition obligation amortization		0.2			0.2			0.2			0.2
Amortization of actuarial loss		-			-			0.4			0.5
Amount attributable to Company affiliates		(0.5	)		(0.5	)		(1.3	)		(1.4	)
Net periodic benefit (income) cost	$	(5.1	)	$	(4.1	)	$	3.3		$	3.2

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Six months ended June 30
Service cost	$	6.1		$	5.6		$	1.8		$	1.6
Interest cost		19.0			18.7			5.6			5.8
Expected return on assets		(38.2	)		(35.5	)		-			-
Prior service cost amortization		3.4			3.2			0.6			0.4
Transition obligation amortization		0.4			0.4			0.4			0.4
Amortization of actuarial loss		-			-			0.8			1.0
Amount attributable to Company affiliates		(0.9	)		(0.9	)		(2.6	)		(2.8	)
Net periodic benefit (income) cost	$	(10.2	)	$	(8.5	)	$	6.6		$	6.4

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.”

Options, all of which were granted prior to 2003, were granted with exercise prices equal to the fair market value of SCANA’s common stock on the respective grant dates since the Plan’s inception; 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 as follows:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
Net income - as reported (millions)	$38	$55	$88	$107
Net income - pro forma (millions)	$38	$55	$88	$107

SCANA also grants other forms of equity based compensation to certain employees of the Company. The value of such awards is recognized as compensation expense under APB 25. Total expense recorded for these awards was approximately $1.8 million and $3.1 million for the three and six months ended June 30, 2005, respectively, and approximately $1.6 million and $3.1 million for the corresponding periods ended June 30, 2004, respectively.

F.      New Accounting Matters

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

Financial Accounting Standards Board Interpretation (FIN) 47, “Accounting for Conditional Asset Retirement Obligations,” was issued in March 2005 to clarify the term “conditional asset retirement” as used in SFAS 143, “Accounting for Asset Retirement Obligations.” It requires that a liability be recognized for the fair value of a conditional asset retirement obligation when incurred, if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation would be factored into the measurement of the liability when sufficient information exists. 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. The Company does not expect that the initial adoption of FIN 47 will have a material impact on the Company’s results of operations, cash flows or financial position.

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

G.      Reclassifications

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

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2.       RATE AND OTHER REGULATORY MATTERS

Electric

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

In the January 2005 order the SCPSC also approved recovery over a five-year period of SCE&G's approximately $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization and recovery through base rates over three years of approximately $25.6 million of purchased power costs that were previously deferred. As a part of its order, the SCPSC extended through 2010 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station up to $36 million annually without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.

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

Rate Per KWh	Effective Date
$.01678	January-April 2004
$.01821	May-December 2004
$.01764	January-April 2005
$.02256	May-June 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 June 30, 2005 was as follows:

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

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

3.       DEBT AND CREDIT FACILITIES

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

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

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

4.        RETAINED EARNINGS

SCE&G’s Restated Articles of Incorporation contain provisions that, under certain circumstances, which SCE&G considers remote, could limit the payment of cash dividends on its common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At June 30, 2005, of SCE&G’s approximately $934 million in retained earnings, approximately $50 million were restricted by this requirement as to payment of cash dividends on common stock.

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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 June 30, 2005 include the following:

A. Nuclear Insurance

The Price-Anderson Indemnification Act (the Act) deals with public liability for a nuclear incident. Though the Act expired in 2003, existing licensees, such as the Company, are “grandfathered” under the Act until such time as it is renewed. The Act establishes the liability limit for third party claims associated with any nuclear incident at $10.5 billion. Each reactor licensee is currently liable for up to $100.6 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $10 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station, would be approximately $67.1 million per incident, but not more than $6.7 million per year.

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

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

B.    Environmental

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

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

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

At SCE&G, site assessment and cleanup costs are deferred and are being recovered through rates (see Note 1). Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $13.6 million at June 30, 2005. The deferral includes the estimated costs associated with the following matters.

SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for contamination. SCE&G anticipates that the remaining remediation activities will be completed by the end of 2005, with certain monitoring and retreatment activities continuing until 2010. As of June 30, 2005, SCE&G had spent approximately $20.9 million to remediate the Calhoun Park site and expects to spend an additional $1.0 million. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of approximately $9 million for certain costs and damages relating to this site. Any costs arising from these matters are expected to be recoverable through rates under South Carolina regulatory process.

SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. One of the sites has been remediated and will undergo routine monitoring until released by the South Carolina Department of Health and Environmental Control (DHEC). The other sites are currently being investigated under work plans approved by DHEC. SCE&G anticipates that major remediation activities for the three sites will be completed in 2010. As of June 30, 2005, SCE&G had spent approximately $4.2 million related to these three sites, and expects to spend an additional $8.3 million.

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C.      Claims and Litigation

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

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

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

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

6.        SEGMENT OF BUSINESS INFORMATION

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

	2005									2004
			Operating			Net						Operating			Net
	External		Income			Income			Segment	External		Income			Income		Segment
Millions of Dollars	Revenue		(Loss)			(Loss)			Assets	Revenue		(Loss)			(Loss)		Assets
Three Months Ended June 30,
Electric Operations	$	438	$	83			n/a			$	435	$	120			n/a
Gas Distribution		85		(5	)		n/a				68		(6	)		n/a
All Other		-		-			(5	)			-		-			-
Adjustments/Eliminations		-		-			43				-		-		$	55
Consolidated Total	$	523	$	78		$	38			$	503	$	114		$	55
Six Months Ended June 30,

Electric Operations	$	854	$	8			n/a		$	5,287	$	817	$	217		n/a		$	5,169
Gas Distribution		242		12			n/a			381		213		10		n/a			328
All Other		-		-			(69	)		3		-		-	$	(1	)		3
Adjustments/Eliminations		-		(1	)		157			1,301		-		-		108			1,214
Consolidated Total	$	1,096	$	19		$	88		$	6,972	$	1,030	$	227	$	107		$	6,714

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

SOUTH CAROLINA ELECTRIC & GAS COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations appearing in South Carolina Electric & Gas Company’s (SCE&G, and together with its consolidated affiliates, the Company) Annual Report on Form 10-K for the year ended December 31, 2004.

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

Electric Operations

  The Energy Policy Act of 2005 (the “energy bill”) passed both houses of Congress in July 2005 and is expected to be signed by the President in August 2005.   Some 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.  Also, the energy bill repeals the Public Utility Holding Company Act of 1935, and provides for greater regulatory oversight by other federal and state authorities.  The Company is reviewing the energy bill to determine the impact it will 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

On April 26, 2005, SCE&G filed an application with the Public Service Commission of South Carolina (SCPSC) requesting a 7.09 percent increase in retail natural gas base rates, or approximately $28 million based on an adjusted test year ended December 31, 2004. A hearing on this request is expected to be held in September 2005. If approved, it is anticipated that the new rates would go into effect in November 2005.

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

RESULTS OF OPERATIONS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2005

AS COMPARED TO THE CORRESPONDING PERIODS IN 2004

Net Income

Net income was as follows:

	Second Quarter		Year to Date
Millions of dollars	2005	2004	2005	2004
Net income	$39.9	$56.9	$92.0	$110.7

39

Second Quarter

Net income decreased by approximately $3.8 million due to higher depreciation and operating expenses related to the Jasper County Electric Generating Station, $19.8 million due to milder weather, $1.4 million due to increased interest expense, $2.2 million due to new depreciation rates and $1.5 million due to other operating expenses. These decreases were partially offset by approximately $9.7 million from increased retail electric rates that went into effect in January 2005, off-system sales of $2.6 million and increased growth and consumption of $2.0 million. 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 decreased by approximately $11.0 million due to higher depreciation and operating expenses related to the Jasper County Electric Generating Station, $25.2 million due to milder weather, $2.8 million due to increased interest expense, $4.4 million due to new depreciation rates and $4.6 million due to other operating expenses. These decreases were partially offset by approximately $19.3 million from increased retail electric rates that went into effect in January 2005, off-system sales of $2.6 million and increased growth and consumption of $7.4 million. Accelerated depreciation on the Lake Murray back-up dam and recognition of synthetic fuel tax credits and related items had no effect on net income, as discussed below.

Recognition of Synthetic Fuel Tax Credits

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

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

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

Factors Increasing (Decreasing) Net Income (millions)	Recognized 2nd Quarter 2005			Year to Date 2005
Recognized in Statement of Income:
Depreciation and amortization expense	$	(13.9	)	$	(183.6	)
Income tax benefits:
From synthetic fuel tax credits		11.2			155.2
From accelerated depreciation		5.3			70.2
From partnership losses		1.6			25.9
Total income tax benefits		18.1			251.3
Losses from Equity Method Investments		(4.2	)		(67.7	)
Impact on Net Income		-			-

40

Pension Income

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

	Second Quarter				Year to Date
Millions of dollars	2005		2004		2005		2004
Income Statement Impact:
Reduction in employee benefit costs	$	1.5	$	1.1	$	3.0	$	2.4
Other income		3.1		2.6		6.1		5.1
Balance Sheet Impact:
Reduction in capital expenditures		0.4		0.3		0.8		0.7
Component of amount due to Summer Station co-owner		0.1		0.1		0.3		0.3
Total Pension Income	$	5.1	$	4.1	$	10.2	$	8.5

 

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 second quarter and year to date 2005 increased compared to the corresponding periods in 2004, primarily as a result of positive investment returns.

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 June 30, 2005 decreased slightly primarily due to completion of the Jasper County Electric Generating Station in May 2004. Included in the equity portion of AFC for the three and six months ended June 30, 2005 is approximately $2.8 million and $5.6 million, respectively, which was accrued as a result of the January 2005 SCPSC rate order related to construction costs for the back-up dam at Lake Murray.

Dividends Declared

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

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

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 were as follows:

	Second Quarter							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004
Operating revenues	$	438.2		0.6	%	$	435.4	$	854.5		4.6	%	$	816.6
Less: Fuel used in generation		137.2		14.2	%		120.1		265.0		23.0	%		215.5
Purchased power		11.0		(44.4	)%		19.8		17.6		(45.8	)%		32.5
Margin	$	290.0		(1.9	)%	$	295.5	$	571.9		0.6	%	$	568.6

Second Quarter

Margin decreased primarily due to unfavorable weather, which had an impact of $19.8 million. This decrease was offset by $9.7 million due to increased retail electric rates that went into effect in January 2005, by $2.6 million related to increased off-system sales and by customer growth and increased consumption of $2.0 million.

Year to Date

Margin increased primarily due to increased retail electric rates that went into effect in January 2005, which had an impact of $19.3 million, by $2.6 million related to increased off-system sales and by customer growth and increased consumption of $7.4 million. These factors were partially offset by $25.2 million due to unfavorable weather.

41

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:

	Second Quarter							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004
Operating revenues	$	84.8		24.9	%	$	67.9	$	241.7		13.2	%	$	213.5
Less: Gas purchased for resale		71.0		28.4	%		55.3		191.7		15.4	%		166.1
Margin	$	13.8		9.5	%	$	12.6	$	50.0		5.5	%	$	47.4

Second Quarter and Year to Date

Margin increased primarily due to customer growth.

Other Operating Expenses

Other operating expenses were as follows:

	Second Quarter							Year to Date
Millions of dollars	2005		% Change			2004		2005		% Change			2004
Other operation and maintenance	$	112.5		8.7	%	$	103.5	$	221.9		4.6	%	$	212.2
Depreciation and amortization		77.7		*			55.5		311.2		*			107.4
Other taxes		36.0		3.7	%		34.7		70.9		1.7	%		69.7
Total	$	226.2		*		$	193.7	$	604.0		*		$	389.3

*Not meaningful

Second Quarter

Other operation and maintenance expenses increased primarily due to increased nuclear and fossil maintenance expenses of $6.8 million. Depreciation and amortization increased approximately $13.9 million due to accelerated depreciation of the back-up dam at Lake Murray (previously explained at Recognition of Synthetic Fuel Tax Credits) and increased $2.7 million due to the completion of the Jasper County Electric Generating Station in May 2004 and $1.4 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 $4.4 million of additional depreciation expense in the period.

Year to Date

Other operation and maintenance expenses increased primarily due to increased nuclear and fossil maintenance expenses of $11.4 million, partially offset by decreases in storm expenses of $1.9 million and $1.9 million of employee benefit expenses. Depreciation and amortization increased approximately $183.6 million due to accelerated depreciation of the back-up dam at Lake Murray (previously explained at Recognition of Synthetic Fuel Tax Credits) and increased $8.7 million due to the completion of the Jasper County Electric Generating Station in May 2004 and $2.9 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 $8.7 million of additional depreciation expense in the period.

Interest Expense

Interest expense for the three and six months ended June 30, 2005 increased primarily due to reduced AFC of $4.6 million which was partially offset by lower interest rates and reduced long-term debt.

Income Taxes

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

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its contractual cash obligations will be met through internally generated funds 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 June 30, 2005 was 2.94.

42

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

In a January 2005 order the SCPSC granted SCE&G a composite increase in retail electric rates of approximately 2.89%, designed to produce additional annual revenues of approximately $41.4 million based on a test year calculation. The SCPSC lowered SCE&G's return on common equity from 12.45% to an amount not to exceed 11.4%, with rates to be set at 10.7%. The new rates became effective in January 2005. As part of its order, the SCPSC approved SCE&G's recovery of construction and operating costs for SCE&G's new Jasper County Electric Generating Station, recovery of costs of mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray (as previously discussed 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 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.

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

	Six Months Ended
	June 30,
Millions of dollars	2005			2004
Net cash provided from operating activities	$	73		$	165
Net cash provided from financing activities		115			37
Cash provided from sale of assets		1			1
Cash and cash equivalents available at the beginning of the period		20			56
Funds used for utility property additions and construction expenditures	$	(183	)	$	(232	)
Funds used for investments		(9	)		(8	)

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

CAPITAL TRANSACTIONS

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

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

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

CAPITAL PROJECTS

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

43

ENVIRONMENTAL MATTERS

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

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

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

OTHER MATTERS

Synthetic Fuel

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

The aggregate investment in these partnerships as of June 30, 2005 is approximately $2.8 million, and through June 30, 2005, they have generated and passed through to SCE&G approximately $155.2 million in such tax credits. As previously described at Net Income, in a January 2005 order, the SCPSC approved SCE&G’s request to apply these synthetic fuel tax credits to offset the construction costs of the Lake Murray Dam project. Under the accounting methodology approved by the SCPSC, construction costs related to the project are recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation is recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

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

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

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

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

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

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

44

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 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 June 30, 2005
Millions of dollars				Expected Maturity Date
							There-		Fair
Liabilities	2005	2006	2007		2008	2009	after	Total	Value
Long-Term Debt:
Fixed Rate ($)	3.7	169.9	39.2		39.2	139.2	1,718.2	2,109.4	2,285.7
Average Interest Rate (%)	7.78	8.51	6.86		6.86	6.33	5.88	6.16	n/a

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

Item 4. Controls and Procedures

As of June 30, 2005 an evaluation was performed under the supervision and with the participation of the Company’s management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based on that evaluation, the Company’s management, including the CEO and CFO, concluded that as of June 30, 2005 the Company’s disclosure controls and procedures were effective. There has been no change in the Company’s internal control over financial reporting during the quarter ended June 30, 2005 that has materially affected or is reasonably likely to materially affect the Company’s internal control over financial reporting.

45

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).

46

Item 1. Financial Statements.

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

(Unaudited)

	June 30,			December 31,
Millions of dollars	2005			2004
Assets
Gas Utility Plant	$	971		$	947
Accumulated depreciation		(274	)		(262	)
Acquisition adjustment		210			210
Gas Utility Plant, Net		907			895
Nonutility Property and Investments, Net		27			27
Current Assets:
Cash and cash equivalents		28			1
Restricted cash and temporary investments		-			8
Receivables, net of allowance for uncollectible accounts of $3 and $2		44			128
Receivables-affiliated companies		3			7
Inventories (at average cost):
Stored gas		55			70
Materials and supplies		5			5
Prepayments		1			2
Deferred income taxes, net		4			4
Other		-			1
Total Current Assets		140			226
Deferred Debits:
Due from affiliate-pension asset		11			12
Regulatory assets		15			27
Other		5			4
Total Deferred Debits		31			43
Total	$	1,105		$	1,191

47

	June 30,		December 31,
Millions of dollars	2005		2004
Capitalization and Liabilities
Capitalization:
Common equity	$	531	$	513
Long-term debt, net		270		274
Total Capitalization		801		787
Current Liabilities:
Short-term borrowings		-		58
Current portion of long-term debt		3		3
Accounts payable		27		66
Accounts payable-affiliated companies		7		8
Customer deposits		8		8
Taxes accrued		2		4
Interest accrued		6		6
Distributions/dividends declared		4		4
Other		6		17
Total Current Liabilities		63		174
Deferred Credits:
Deferred income taxes, net		105		105
Deferred investment tax credits		1		1
Due to affiliate-postretirement benefits		19		19
Other regulatory liabilities		15		10
Asset retirement obligations		88		84
Other		13		11
Total Deferred Credits		241		230
Commitments and Contingencies (Note 5)		-		-
Total	$	1,105	$	1,191

See Notes to Condensed Consolidated Financial Statements.

48

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Millions of dollars	2005			2004			2005		2004
Operating Revenues	$	84		$	69		$	329	$	296
Cost of Gas		53			42			225		196
Gross Margin		31			27			104		100
Operating Expenses:
Operation and maintenance		19			19			40		40
Depreciation and amortization		9			9			17		17
Other taxes		2			2			4		4
Total Operating Expenses		30			30			61		61
Operating Income (Loss)		1			(3	)		43		39
Other Income, Including Allowance for Equity Funds Used During Construction		-			-			2		-
Interest Charges, Net of Allowance for Borrowed Funds Used During Construction		5			5			11		10
Income (Loss) Before Income Tax Expense (Benefit) and
Earnings from Equity Method Investments		(4	)		(8	)		34		29
Income Tax Expense (Benefit)		(1	)		(3	)		14		12
Income (Loss) Before Earnings from Equity Method Investments		(3	)		(5	)		20		17
Earnings from Equity Method Investments		1			1			2		2
Net Income (Loss)	$	(2	)	$	(4	)	$	22	$	19

 

      See Notes to Condensed Consolidated Financial Statements.

49

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

(Unaudited)

	Six Months Ended
	June 30,
Millions of dollars	2005			2004
Cash Flows From Operating Activities:
Net income	$	22		$	19
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization		18			18
Loss on sale of assets		-			1
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		88			84
Inventories		15			14
Regulatory assets		(3	)		-
Regulatory liabilities		1			1
Accounts payable		(41	)		(20	)
Taxes accrued		(2	)		(7	)
Changes in gas adjustment clauses		19			2
Changes in other assets		2			2
Changes in other liabilities		(8	)		(1	)
Net Cash Provided From Operating Activities		111			113
Cash Flows From Investing Activities:
Construction expenditures, net of AFC		(24	)		(26	)
Nonutility and other		6			(1	)
Net Cash Used For Investing Activities		(18	)		(27	)
Cash Flows From Financing Activities:
Short-term borrowings, net		(58	)		(55	)
Net capital contribution from parent		2			-
Retirement of long-term debt		(3	)		(3	)
Distributions/dividends		(7	)		(8	)
Net Cash Used For Financing Activities		(66	)		(66	)
Net Increase In Cash and Cash Equivalents		27			20
Cash and Cash Equivalents, January 1		1			18
Cash and Cash Equivalents, June 30	$	28		$	38
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $0.2 and $0.4)	$	9		$	9
- Income taxes		17			19
Noncash Investing and Financing Activities:
Accrued construction expenditures		0.8			0.4

See Notes to Condensed Consolidated Financial Statements.

50

June 30, 2005

(Unaudited)

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

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.  Basis of Accounting

The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS 71 requires cost-based rate-regulated utilities to recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, as of June 30, 2005 the Company has recorded approximately $15 million and $103 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.

	June 30,			December 31,
Millions of dollars	2005			2004
Excess deferred income taxes	$	(2	)	$	(1	)
Under- (over-) collections-gas cost adjustment clause, net		(9	)		10
Deferred environmental remediation costs		11			8
Asset retirement obligations		(88	)		(84	)
Total	$	(88	)	$	(67	)

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

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

Deferred environmental remediation costs represent costs associated with the assessment and 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 $2.4 million. Management believes that these costs and the remaining costs of approximately $8.8 million will be recoverable.

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

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

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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 $(0.6) million and $(0.7) million as of June 30, 2005 and December 31, 2004, respectively.

C. New Accounting Matters

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

Financial Accounting Standards Board Interpretation (FIN) 47, “Accounting for Conditional Asset Retirement Obligations,” was issued in March 2005 to clarify the term “conditional asset retirement” as used in SFAS 143, “Accounting for Asset Retirement Obligations.” It requires that a liability be recognized for the fair value of a conditional asset retirement obligation when incurred, if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation would be factored into the measurement of the liability when sufficient information exists. 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. The Company does not expect that the initial adoption of FIN 47 will have a material impact on the Company’s results of operations, cash flows or financial position.

D. Reclassifications

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

2. RATE AND OTHER REGULATORY MATTERS

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

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

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

 On August 1, 2005 the NCUC approved the Company's request to increase the benchmark cost of gas from $.725 per therm to $.825 per therm for service rendered on and after August 1, 2005.

On June 1, 2005 the Company filed testimony in the 2005 Annual Prudence Review related to the 12 months ended March 31, 2005. The NCUC will hold a hearing in August 2005 to consider the filing.

A state expansion fund, established by the North Carolina General Assembly in 1991 and funded by refunds from the Company’s interstate pipeline transporters, provides financing for expansion into area that otherwise would not be economically feasible to serve. On May 12, 2005 the Company filed an application with the NCUC to extend natural gas service to Louisburg, North Carolina and requested authorization to withdraw approximately $1.2 million from its expansion fund for this project. The NCUC will hold a hearing in August 2005 to consider the filing.

In March 2005 the Company refunded approximately $7.7 million in pipeline supplier refunds by a direct bill credit to various customers. This refund resulted in a reduction in restricted cash and the associated current liability.

On January 21, 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. As of June 30, 2005 such deferrals totaled $0.3 million.

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3.  FINANCIAL INSTRUMENTS

The Company follows the guidance required by SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended, in accounting for derivatives, including those arising from cash flow hedges related to natural gas. The Company also utilizes swap agreements to manage interest rate risk. These transactions are more fully described in Note 7 to the consolidated financial statements in the Company’s 2004 Annual Report on Form 10-K.

The Company utilizes hedging activities for natural gas purchases. Transaction fees and any realized gains or losses are recorded in deferred accounts for subsequent rate consideration. As of June 30, 2005 the Company had deferred net costs of approximately $3.2 million.

The Company also utilizes swap agreements to manage interest rate risk. At June 30, 2005 the estimated fair value of the Company’s swap was $1.0 million (gain) related to combined notional amounts of $22.4 million.

4.  LONG-TERM DEBT

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 $8.8 million, which reflects its estimated remaining liability at June 30, 2005. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates are approximately $2.4 million. Management believes that all MGP cleanup costs will be recoverable through gas rates.

6. SEGMENT OF BUSINESS INFORMATION

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

			2005									2004
					Net							Operating			Net
	External		Operating		Income			Segment		External		Income			Income			Segment
(Millions of dollars)	Revenue		Income		(Loss)			Assets		Revenue		(Loss)			(Loss)			Assets
Three Months Ended June 30,
Gas Distribution	$	84	$	1	$	(2	)			$	69	$	(3	)	$	(4	)
All Other		-		n/a		-					-		n/a			-
Adjustments/Eliminations		-		-		-					-		-			-
Consolidated Total	$	84	$	1	$	(2	)			$	69	$	(3	)	$	(4	)
Six Months Ended June 30,
Gas Distribution	$	329	$	43	$	22		$	1,007	$	296	$	39		$	19		$	996
All Other		-		n/a		-			28		-		n/a			-			28
Adjustments/Eliminations		-		-		-			70		-		-			-			61
Consolidated Total	$	329	$	43	$	22		$	1,105	$	296	$	39		$	19		$	1,085

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PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

MANAGEMENT’S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

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

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

Net Income and Distributions/Dividends

Net income for the six months ended June 30, 2005 increased $3.7 million compared to the same period in 2004, primarily due to increased margin.

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

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

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

Gas Distribution

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

	Six Months Ended June 30,
Millions of dollars	2005		% Change			2004
Operating revenues	$	329.7		11.6	%	$	295.4
Less: Gas purchased for resale		225.3		15.0	%		195.9
Margin	$	104.4		4.9	%	$	99.5

Gas distribution sales margin for the six months ended June 30, 2005 increased by approximately $4.9 million primarily due to increased residential customer growth and increased consumption.

Other Income

Other income in 2005 improved primarily due to the recognition of a $1.0 million loss in 2004 on the sale of PSNC Energy’s former corporate headquarters.

Income Taxes

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

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Capital Expansion Program and Liquidity Matters

PSNC Energy’s capital expansion program includes the construction of lines, systems and facilities and the purchase of related equipment. PSNC Energy’s 2005 construction budget is approximately $58 million, compared to actual construction expenditures through June 30, 2005 of $25.2 million. PSNC Energy’s ratio of earnings to fixed charges for the 12 months ended June 30, 2005 was 3.08.

At June 30, 2005 PSNC Energy had no outstanding short-term borrowings. 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.

As of June 30, 2005 an evaluation was performed under the supervision and with the participation of PSNC Energy’s management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of PSNC Energy’s disclosure controls and procedures. Based on that evaluation, PSNC Energy’s management, including the CEO and CFO, concluded that as of June 30, 2005 PSNC Energy’s disclosure controls and procedures were effective. There has been no change in PSNC Energy’s internal control over financial reporting during the quarter ended June 30, 2005 that has materially affected or is reasonably likely to materially affect PSNC Energy’s internal control over financial reporting.

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A complaint was filed on October 22, 2003 against South Carolina Electric & Gas Company (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 Corporation (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 reasonable. However, SCANA continues to believe that the verdict was inconsistent with the facts presented and applicable laws. Both parties have appealed the judgment.

SCANA is also defending another claim for $2.7 million for reimbursement of legal fees and expenses under an indemnification and hold harmless agreement in the contract for the sale of these propane gas assets. A bench trial on the indemnification was held on January 14, 2005; however, a ruling has not been received. SCANA believes that the resolution of this claim will not have a material adverse impact on its results of operations, cash flows or financial condition.

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

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Item 4. Submission of Matters to a Vote of Security-Holders (not applicable for South Carolina Electric & Gas

            Company and Public Service Company of North Carolina Incorporated).

At the Annual Meeting of Shareholders of SCANA Corporation (SCANA) held on May 5, 2005, the shareholders of SCANA voted on the following three items:

1. To elect three Class III Directors for the terms specified in the Proxy Statement.

Nominee	Number of Shares Voting For	Number of Shares Voting to Withhold Authority	Total Shares Voted
Bill L. Amick	95,208,223	1,470,918		96,679,141
D. Maybank Hagood	95,374,039	1,305,102		96,679,141
William B. Timmerman	95,098,415	1,580,726		96,679,141

2. To approve the amended and restated Long-Term Equity Compensation Plan

	Number of Shares
FOR	65,829,794
AGAINST	4,359,918
ABSTAIN	1,321,891
BROKER NON-VOTES	30,287,473
TOTAL	101,799,076

3. To approve the appointment of Deloitte & Touche LLP as the independent registered public accounting firm for

the Corporation.

	Number of Shares
FOR	95,348,835
AGAINST	877,817
ABSTAIN	452,489
TOTAL	96,679,141

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

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

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

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

SCANA CORPORATION

SOUTH CAROLINA ELECTRIC & GAS COMPANY

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

(Registrants)

By:	/s/James E. Swan, IV
August 5, 2005	James E. Swan, IV
	Controller
	(Principal accounting officer)

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

3.11		X		Articles of Amendment dated March 9, 2005 amending the Restated Articles of Incorporation of South Carolina Electric & Gas Company (Filed as Exhibit 3.11 to Form 10-Q for the quarter ended March 31, 2005)
3.12		X		Articles of Amendment dated May 16, 2005 amending the Restated Articles of Incorporation of South Carolina Electric & Gas Company (Filed herewith)
3.13		X		Articles of Amendment dated June 15, 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 herewith)
31.01	X			Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.02	X			Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
31.03		X		Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.04		X		Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
31.05			X	Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.06			X	Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
32.01	X			Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.02	X			Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.03		X		Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.04		X		Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.05			X	Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.06			X	Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

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