Scana 10-Q 2006 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2006

OR

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

For the Transition Period from               to                        

Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.
1-8809	SCANA Corporation	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 ¨ South Carolina Electric & Gas Company Yes x No ¨ Public Service Company of North Carolina, Incorporated Yes x No ¨

 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definitions of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act).

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

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

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

Yes ¨ No x  

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

Registrant	Description of  Common Stock	Shares Outstanding at July 31, 2006
SCANA Corporation	Without Par Value	116,006,325
South Carolina Electric & Gas Company	$4.50 Par Value	40,296,147 (a)
Public Service Company of North Carolina, Incorporated	Without Par Value	1,000 (a)
(a)Owned beneficially and of record by SCANA Corporation.

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

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

INDEX TO FORM 10-Q

JUNE 30, 2006

PART I. FINANCIAL INFORMATION				Page
SCANA Corporation Financial Section				3
	Item 1.		Financial Statements
			Condensed Consolidated Balance Sheets	4
			Condensed Consolidated Statements of Income	6
			Condensed Consolidated Statements of Cash Flows	7
			Condensed Consolidated Statements of Comprehensive Income	8
			Notes to Condensed Consolidated Financial Statements	9
	Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
	Item 3.		Quantitative and Qualitative Disclosures About Market Risk	28
South Carolina Electric & Gas Company Financial Section				30
	Item 1.		Financial Statements
			Condensed Consolidated Balance Sheets	31
			Condensed Consolidated Statements of Income	33
			Condensed Consolidated Statements of Cash Flows	34
			Notes to Condensed Consolidated Financial Statements	35
	Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations	46
	Item 3.		Quantitative and Qualitative Disclosures About Market Risk	52
Public Service Company of North Carolina, Incorporated Financial Section				53
	Item 1.		Financial Statements
			Condensed Consolidated Balance Sheets	54
			Condensed Consolidated Statements of Operations	56
			Condensed Consolidated Statements of Cash Flows	57
			Notes to Condensed Consolidated Financial Statements	58
	Item 2.		Management’s Narrative Analysis of Results of Operations	62
Item 4.		Controls and Procedures		64
PART II. OTHER INFORMATION				65
Item 1.		Legal Proceedings		65
Item 4.		Submission of Matters to a Vote of Security Holders		65
Item 6.		Exhibits		66
Signatures				67
Exhibit Index				68

SCANA CORPORATION

FINANCIAL SECTION

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SCANA CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,			December 31,
Millions of dollars	2006			2005
Assets
Utility Plant In Service	$	9,136		$	8,999
Accumulated Depreciation and Amortization		(2,712	)		(2,688	)
		6,424			6,311
Construction Work in Progress		216			175
Nuclear Fuel, Net of Accumulated Amortization		41			28
Acquisition Adjustments		230			230
Utility Plant, Net		6,911			6,744
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $64 and $62		120			108
Assets held in trust, net - nuclear decommissioning		52			52
Other investments		92			87
Nonutility Property and Investments, Net		264			247
Current Assets:
Cash and cash equivalents		160			62
Receivables, net of allowance for uncollectible accounts of $21 and $25		520			881
Receivables - affiliated companies		22			24
Inventories (at average cost):
Fuel		256			284
Materials and supplies		88			79
Emission allowances		20			7
Prepayments and other		52			54
Deferred income taxes		30			26
Total Current Assets		1,148			1,417
Deferred Debits and Other Assets:
Pension asset, net		310			303
Emission allowances		32			47
Regulatory assets		596			617
Other		137			154
Total Deferred Debits and Other Assets		1,075			1,121
Total	$	9,398		$	9,529

 

	June 30,		December 31,
Millions of dollars	2006		2005
Capitalization and Liabilities
Shareholders’ Investment:
Common equity	$	2,773	$	2,677
Preferred stock (Not subject to purchase or sinking funds)		106		106
Total Shareholders’ Investment		2,879		2,783
Preferred Stock, net (Subject to purchase or sinking funds)		8		8
Long-Term Debt, net		3,043		2,948
Total Capitalization		5,930		5,739
Current Liabilities:
Short-term borrowings		248		427
Current portion of long-term debt		213		188
Accounts payable		262		471
Accounts payable - affiliated companies		22		26
Customer deposits and customer prepayments		72		70
Taxes accrued		88		112
Interest accrued		52		52
Dividends declared		51		47
Other		61		107
Total Current Liabilities		1,069		1,500
Deferred Credits and Other Liabilities:
Deferred income taxes, net		958		940
Deferred investment tax credits		121		121
Asset retirement obligations		331		322
Postretirement benefits		152		148
Regulatory liabilities		713		615
Other		124		144
Total Deferred Credits and Other Liabilities		2,399		2,290
Commitments and Contingencies (Note 5)		-		-
Total	$	9,398	$	9,529

See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Millions of dollars, except per share amounts	2006			2005			2006			2005
Operating Revenues:
Electric	$	461		$	440		$	859		$	856
Gas - regulated		215			219			730			680
Gas - nonregulated		268			234			744			624
Total Operating Revenues		944			893			2,333			2,160
Operating Expenses:
Fuel used in electric generation		147			137			264			265
Purchased power		8			13			12			21
Gas purchased for resale		403			376			1,213			1,037
Other operation and maintenance		150			153			307			312
Depreciation and amortization		77			89			153			334
Other taxes		37			40			76			78
Total Operating Expenses		822			808			2,025			2,047
Operating Income		122			85			308			113
Other Income (Expense):
Other income		23			46			81			101
Other expenses		(7	)		(36	)		(53	)		(82	)
Allowance for equity funds used during construction		-			3			-			6
Interest charges, net of allowance for borrowed funds
used during construction of $2, $3, $3 and $1		(53	)		(54	)		(107	)		(108	)
Preferred dividends of subsidiary		(2	)		(2	)		(4	)		(4	)
Gain on sale of investment and assets		-			8			-			8
Total Other Expense		(39	)		(35	)		(83	)		(79	)
Income Before Income Tax Expense (Benefit), Losses from Equity
Method Investments and Cumulative Effect of Accounting Change		83			50			225			34
Income Tax Expense (Benefit)		23			3			69			(176	)
Income Before Losses from Equity Method
Investments and Cumulative Effect of Accounting Change		60			47			156			210
Losses from Equity Method Investments		(2	)		(3	)		(6	)		(65	)
Cumulative Effect of Accounting Change, net of taxes		-			-			6			-
Net Income	$	58		$	44		$	156		$	145
Basic and Diluted Earnings Per Share of Common Stock:
Before Cumulative Effect of Accounting Change	$	.50		$	.39		$	1.30		$	1.28
Cumulative Effect of Accounting Change, net of taxes		-			-			.05			-
Basic and Diluted Earnings Per Share	$	.50		$	.39		$	1.35		$	1.28
Weighted Average Shares Outstanding (millions)		115.5			113.6			115.3			113.3
See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
Millions of dollars	2006			2005
Cash Flows From Operating Activities:
Net income	$	156		$	145
Adjustments to reconcile net income to net cash provided from operating activities:
Cumulative effect of accounting change, net of taxes		(6	)		-
Losses from equity method investments		6			65
Depreciation and amortization		154			342
Amortization of nuclear fuel		9			8
Gain on sale of assets and investments		-			(8	)
Hedging activities		(3	)		5
Carrying cost recovery		(4	)		(6	)
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		363			139
Inventories		5			(36	)
Prepayments and other		(12	)		17
Pension asset		(7	)		(8	)
Other regulatory assets		10			22
Deferred income taxes, net		14			(29	)
Regulatory liabilities		22			(166	)
Postretirement benefits		4			3
Accounts payable		(214	)		(122	)
Taxes accrued		(25	)		(65	)
Interest accrued		-			1
Changes in fuel adjustment clauses		13			10
Changes in other assets		26			6
Changes in other liabilities		(42	)		10
Net Cash Provided From Operating Activities		469			333
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(224	)		(212	)
Proceeds from sale of assets and investments		18			6
Nonutility property additions		(21	)		(7	)
Investments		(21	)		(27	)
Net Cash Used For Investing Activities		(248	)		(240	)
Cash Flows From Financing Activities:
Proceeds from issuance of debt		123			197
Proceeds from issuance of common stock		40			47
Repayment of debt		(11	)		(456	)
Redemption of preferred stock		-			(1	)
Dividends on equity securities		(97	)		(89	)
Short-term borrowings, net		(178	)		235
Net Cash Used For Financing Activities		(123	)		(67	)
Net Increase In Cash and Cash Equivalents		98			26
Cash and Cash Equivalents, January 1		62			120
Cash and Cash Equivalents, June 30		160		$	146
Supplemental Cash Flow Information:
Cash paid for  - Interest (net of capitalized interest of $3 and $1)		107			110
- Income taxes		38			45
Noncash Investing and Financing Activities:
Accrued construction expenditures		18			14

See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended					Six Months Ended
	June 30,					June 30,
Millions of dollars	2006		2005			2006		2005
Net Income	$	58	$	44		$	156	$	145
Other Comprehensive Income, net of tax:
Unrealized gains (losses) on hedging activities		1		(3	)		3		4
Total Comprehensive Income (1)	$	59	$	41		$	159	$	149
(1) Accumulated other comprehensive income totaled $7.0 million as of June 30, 2006 and $4.2 million as of
December 31, 2005.
See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2006

(Unaudited)

The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in SCANA Corporation’s (SCANA, and together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, 2005. These are interim financial statements, and due to the seasonality of the Company’s business and matters that may occur during the rest of the year, the amounts reported in the Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the full year. In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature, which are necessary for a fair statement of the results for the interim periods reported.

1.      SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.      Basis of Accounting

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

	June 30,		December 31,
Millions of dollars	2006		2005
Regulatory Assets:
Accumulated deferred income taxes	$	177	$	177
Under-collections - electric fuel and gas cost adjustment clauses		36		61
Purchased power costs		13		17
Environmental remediation costs		29		28
Asset retirement obligations and related funding		260		250
Franchise agreements		56		56
Regional transmission organization costs		9		11
Other		16		17
Total Regulatory Assets	$	596	$	617

Regulatory Liabilities:
Accumulated deferred income taxes	$	38	$	39
Over-collections - electric fuel and gas cost adjustment clauses		20		20
Other asset removal costs		579		498
Storm damage reserve		42		38
Planned major maintenance		18		9
Other		16		11
Total Regulatory Liabilities	$	713	$	615

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

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

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

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 $18.5 million remain to be recovered. A portion of the costs incurred at sites owned by Public Service Company of North Carolina, Incorporated (PSNC Energy) has been recovered through rates. Amounts incurred and deferred, net of insurance settlements, that are not currently being recovered by PSNC Energy through rates are $3.6 million. Management believes that these costs and the estimated remaining costs of $6.6 million will be recoverable by PSNC Energy through rates.

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

Franchise agreements represent costs associated with 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 and are expected to be fully amortized over approximately 20 years.

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

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

The storm damage reserve represents an SCPSC approved reserve account for SCE&G capped at $50 million to be collected through rates. The accumulated 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, 2006, no amounts were drawn from this reserve account.

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

The SCPSC and the NCUC (collectively, state commissions) have reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not 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.       Share-Based Compensation

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

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

Liability Awards

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

Under SFAS 123(R) compensation cost of these liability awards is recognized over the three-year performance period based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Cash-settled liabilities totaling $6.4 million were paid during the six months ended June 30, 2006. No such payments were made during the corresponding period in 2005.

Fair value adjustments for performance awards resulted in a reduction to compensation expense recognized in the condensed statements of income, exclusive of the cumulative effect adjustment discussed previously, totaling $(1.9) million and $(0.6) million for the three and six months ended June 30, 2006, respectively, and an increase to compensation expense totaling $2.9 million and $4.8 million for the corresponding periods ended June 30, 2005, respectively. Fair value adjustments resulted in a net credit to capitalized compensation cost of approximately $(0.1) million during the six months ended June 30, 2006, compared with capitalized cost of approximately $0.5 million during the corresponding period in 2005.

Equity Awards

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

	Number of Options	Weighted Average Exercise Price
Outstanding-December 31, 2005	439,270	$27.53
Exercised	(11,341)	$27.12
Outstanding-March 31, 2006	427,929	$27.54
Exercised	(6,805)	$27.48
Outstanding-June 30, 2006	421,124	$27.54

No stock options have been granted since August 2002, and all options were fully vested in August 2005. The options expire ten years after the grant date. At June 30, 2006, all outstanding options were currently exercisable at prices ranging from $25.50-$29.60, and had a weighted-average remaining contractual life of 5.4 years.

All options were granted with exercise prices equal to the fair market value of SCANA’s common stock on the respective grant dates; therefore, no compensation expense was recognized in connection with such grants. If the Company had recognized compensation expense for the issuance of options based on the fair value method described in SFAS 123(R), pro forma net income and earnings per share for the three and six months ended June 30, 2005 would have been as follows:

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

The exercise of stock options during the period was satisfied using original issue shares of the Company’s common stock. The Company realized $0.2 million and $0.5 million upon the exercise of options in the three and six months ended June 30, 2006, respectively. In addition, tax benefits resulting from the exercise of those stock options totaling $0.1 million in each period were credited to additional paid in capital. The Company realized $2.5 million and $7.6 million upon the exercise of options in the three and six months ended June 30, 2005, respectively, and tax benefits resulting from the exercise of those options totaling $0.4 million and $1.2 million were credited to additional paid in capital in those periods.

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	2006			2005			2006		2005
Three months ended June 30,
Service cost	$	3.5		$	3.1		$	1.2	$	0.9
Interest cost		9.9			9.5			2.8		2.8
Expected return on assets		(18.8	)		(19.1	)		-		-
Prior service cost amortization		1.7			1.7			0.2		0.3
Transition obligation amortization		0.1			0.2			0.2		0.2
Amortization of actuarial loss		0.2			-			0.4		0.4
Net periodic benefit (income) cost	$	(3.4	)	$	(4.6	)	$	4.8	$	4.6

Six months ended June 30,
Service cost	$	7.0		$	6.1		$	2.4	$	1.8
Interest cost		19.8			19.0			5.6		5.6
Expected return on assets		(37.6	)		(38.2	)		-		-
Prior service cost amortization		3.4			3.4			0.4		0.6
Transition obligation amortization		0.2			0.4			0.4		0.4
Amortization of actuarial loss		0.4			-			0.7		0.8
Net periodic benefit (income) cost	$	(6.8	)	$	(9.3	)	$	9.5	$	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’s receivables from these affiliated companies were $21.6 million and $24.6 million at June 30, 2006 and December 31, 2005, respectively. SCE&G’s payables to these affiliated companies were $22.0 million and $25.3 million at June 30, 2006 and December 31, 2005, respectively. SCE&G purchased $64.5 million and $62.8 million of synthetic fuel from these affiliated companies for the three months ended June 30, 2006 and 2005, respectively. SCE&G purchased $129.2 million and $113.7 million of synthetic fuel from these affiliated companies for the six month ended June 30, 2006 and 2005, respectively.

F.      New Accounting Matters

The Company adopted SFAS 154, “Accounting Changes and Error Corrections,” in the first quarter of 2006. SFAS 154 requires retrospective application to financial statements of prior periods for every voluntary change in accounting principle unless such retrospective application is impracticable. SFAS 154 replaces APB 20, “Accounting Changes,” and SFAS 3, “Reporting Accounting Changes in Interim Financial Statements,” although it carries forward some of their provisions. The adoption of SFAS 154 had no material impact on the Company’s results of operations, cash flows or financial position.

SFAS 123(R) requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) replaces SFAS 123, “Accounting for Stock-Based Compensation,” and supersedes APB 25, “Accounting for Stock Issued to Employees.” The Company adopted SFAS 123(R) in the first quarter of 2006. The impact on the Company’s results of operations is discussed at Note 1B.

FIN 48, “Accounting for Uncertainty in Income Taxes,” was issued in June 2006. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109,“Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company will adopt FIN 48 in the first quarter of 2007. The Company is continuing to evaluate the impact that adoption of FIN 48 may have 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 2006.

2.      RATE AND OTHER REGULATORY MATTERS

South Carolina Electric & Gas Company (SCE&G)

Electric

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 was as follows:

Rate Per KWh	Effective Date
$.01764	January-April 2005
$.02256	May 2005-April 2006
$.02516	May-June 2006

In connection with the May 2006 fuel component increase, SCE&G agreed to spread the recovery of previously under-collected fuel costs of $38.5 million over a two-year period.

Gas

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

In June 2006, SCE&G reported to the SCPSC that its return on common equity for the twelve months ended March 31, 2006 was 4.38 percent, compared to an allowed return of 10.25 percent. Since the actual return was more than 0.5 percent below the allowed return, and as provided under South Carolina’s Natural Gas Rate Stabilization Act, SCE&G requested an annualized increase in certain natural gas base rates of 3.3 percent, or $18 million. If approved by the SCPSC, this request would return SCE&G’s regulatory return on common equity to the 10.25 percent authorized level. If approved, the rate adjustment would be effective with the first billing cycle in November 2006.

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 for residential, small and medium general service and large general service classes were as follows (rate per therm):

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

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

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

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

PSNC Energy’s benchmark cost of gas in effect during the period January 1, 2005 through June 30, 2006 was as follows:

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

On June 1, 2006, PSNC Energy filed testimony in the 2006 Annual Prudence Review related to the 12 months ended March 31, 2006. The NCUC will hold a hearing in August 2006 to consider the filing.

On April 3, 2006, PSNC Energy filed an application with the NCUC requesting a 4.9 percent, or $28.4 million, increase in its base rates. In that application, PSNC Energy also requested a $7.5 million reduction in the fixed-cost portion of its cost of gas which, if approved, would result in an overall increase of 3.6 percent, or $20.9 million, in rates and charges for natural gas utility service. The rate increase is largely associated with recovering increased plant investment and operating costs. If approved, the new rates will be effective for the 2006-2007 winter season. A hearing is scheduled for August 2006.

On March 14, 2006, the NCUC authorized PSNC Energy to place pipeline supplier refunds that it presently holds and future supplier refunds into the appropriate deferred accounts for the over- or under-recovery of gas costs. Prior to this authorization, refunds from PSNC Energy’s interstate pipeline transporters were placed in a state-approved expansion fund to provide financing for expansion into areas that otherwise would not be economically feasible to serve. In September 2005, the NCUC approved PSNC Energy’s request for disbursement of up to $1.1 million from the state expansion fund to extend natural gas service to Louisburg, North Carolina. The project will be completed in 2006.

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 June 2006 order, the SCPSC found that for the period January through December 2005 SCPC’s gas purchasing policies and practices were prudent and SCPC properly adhered to the gas cost recovery provisions of its gas tariff.

On July 20, 2006, FERC approved the application for merger of SCG Pipeline, Inc., into SCPC, both SCANA subsidiaries, to form Carolina Gas Transmission Corporation (CGTC). CGTC will operate as an open access transportation-only interstate pipeline company. SCANA expects that the merger will be finalized and that CGTC will commence operations by October 1, 2006.

3.       LONG-TERM DEBT

In June 2006 SCE&G issued $125 million of first mortgage bonds having an annual interest rate of 6.25% and maturing July 1, 2036. The proceeds from the sale of these bonds, together with available cash, were used for the payment at maturity of $131 million of SCE&G’s first and refunding mortgage bonds due July 15, 2006, which bore interest at 9.0%.

In anticipation of the issuance of debt, the Company uses interest rate lock or similar agreements to manage interest rate risk. Payments received or made upon termination of such agreements are recorded within long term debt on the balance sheet and are amortized to interest expense over the term of the underlying debt. In connection with the issuance of first mortgage bonds in June 2006, SCE&G received approximately $8.8 million upon the termination of a treasury lock agreement. These proceeds will be amortized over the life of the related debt, thereby reducing its effective interest rate.

4.     FINANCIAL INSTRUMENTS

The Company utilizes various financial derivatives, including those designated as cash flow hedges related to natural gas. The Company also utilizes swap agreements to manage interest rate risk. These transactions are more fully described in Note 9 to the consolidated financial statements in SCANA’s Annual Report on Form 10-K for the year ended December 31, 2005.

At June 30, 2006 the estimated fair value of the Company’s swaps totaled $0.5 million (loss) related to combined notional amounts of $44.2 million.

The Company’s regulated gas operations (SCE&G, SCPC and PSNC Energy) hedge gas purchasing activities using New York Mercantile Exchange (NYMEX) futures, options or swaps. SCE&G’s and SCPC's tariffs include a purchased gas adjustment (PGA) clause that provide for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of these hedging activities are to be included in the PGA. As such, costs of related derivatives utilized to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. PSNC Energy's tariffs include a provision for the recovery of actual gas costs incurred. PSNC Energy records transaction fees and any realized and unrealized gains or losses from derivatives acquired as part of its hedging program in deferred accounts as a regulatory asset or liability for the over- or under-recovery of gas costs.

The Company’s nonregulated gas operations recognize gains and losses as a result of qualifying cash flow hedges whose hedged transactions occur during the reporting period and record them, net of taxes, in cost of gas. The Company recognized a loss of $4.6 million and a loss of $17.6 million for the three and six months ended June 30, 2006, respectively, and recognized a gain of $0.5 million and a loss of $2.7 million for the corresponding periods ended June 30, 2005, respectively. Because these gains and losses resulted from hedging activities, their effects were necessarily offset by the recording of the related hedged transactions.  The Company estimates that the June 30, 2006 unrealized loss balance of $5.7 million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in 2006 as an increase to gas cost if market prices remain at current levels. As of June 30, 2006, all of the Company's cash flow hedges settle by their terms before the end of December 2007.

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain of its natural gas storage facilities.  At June 30, 2006, such counterparties held 45% of PSNC Energy’s total natural gas inventory, with a value of $33.7 million.  This natural gas will be returned to PSNC Energy at its city gate during the winter period (November 2006 through March 2007), or on the contract settlement date, as applicable.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees and, in certain instances, a share of excess profits.  No fees are received under supply service agreements.  The agreements expire at various times from October 31, 2006 through March 31, 2007.

5.    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, 2005. Commitments and contingencies at June 30, 2006 include the following:

A.    Nuclear Insurance

The Price-Anderson Indemnification Act deals with public liability for a nuclear incident and establishes the liability limit for third-party claims associated with any nuclear incident at $10.5 billion. Each reactor licensee is currently liable for up to $100.6 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $15 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station, would be $67.1 million per incident, but not more than $10 million per year.

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property 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 $15.6 million.

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

B.    Environmental

South Carolina Electric & Gas Company

In March 2005, the Environmental Protection Agency (EPA) issued a final rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. SCE&G has petitioned the United States Court of Appeals for the District of Columbia Circuit to review CAIR. Several other electric utilities have filed separate petitions. The petitioners seek a change in the method CAIR uses to allocate sulfur dioxide emission allowances to a method the petitioners believe is more equitable. The Company believes that installation of additional air quality controls will be needed to meet the CAIR requirements. The Company is reviewing the final rule. Compliance plans and cost to comply with the rule will be determined once the Company completes its review. Such costs may 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. Although the Company expects to be able to meet the Phase I limits through those measures it already will be taking to meet its CAIR obligations, it is uncertain as to how the Phase II limits will be met. Assuming Phase II limits remain unchanged, installation of additional air quality controls likely will be required to comply with the rule’s Phase II mercury emission caps. Final compliance plans and costs to comply with the rule are still under review. Such costs will be material and are expected to be recoverable through rates.

SCE&G has been named, along with 29 others, by the EPA as a potentially responsible party (PRP) at the Carolina Transformer Superfund site located in Fayetteville, North Carolina.  The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from 1967 to 1984.  During that time, SCE&G occasionally used CTC for the repair of existing transformers and the purchase of new transformers.  In 1984, EPA initiated a cleanup of PCB-contaminated soil and groundwater at the site.  EPA reports that it has spent $36 million to date.  SCE&G’s records indicate that only minimal quantities of used transformers were shipped to CTC, and it is not clear if any contained PCB-contaminated oil.  Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G is expected to be recoverable through rates.

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

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

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 $18.5 million at June 30, 2006. The deferral includes the estimated costs associated with the following matters.

SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. SCE&G anticipates that remediation for contamination at the site will be completed in late 2006, with certain monitoring and retreatment activities continuing until 2011. As of June 30, 2006, SCE&G had spent $21.7 million to remediate the site and expects to spend an additional $1.7 million prior to entering a monitoring and reporting stage. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to this site. Any cost arising from the remediation of this site is expected to be recoverable through rates.

SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. One of the sites has been remediated and will undergo routine monitoring until released by the South Carolina Department of Health and Environmental Control (DHEC). The other sites are currently being investigated under work plans approved by DHEC. SCE&G anticipates that major remediation activities for the three sites will be completed by 2010. As of June 30, 2006, SCE&G had spent $4.6 million related to these three sites, and expects to spend an additional $11.5 million. Any cost arising from the remediation of these sites is expected to be recoverable through rates.

  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 remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. PSNC Energy has recorded a liability and associated regulatory asset of $6.6 million, which reflects its estimated remaining liability at June 30, 2006. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through rates are $3.6 million. Any cost arising from the remediation of these sites is expected to be recoverable through 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.  In accordance with generally accepted accounting principles, in the third quarter of 2004 SCANA accrued a liability of $18 million, which was its reasonable estimate of the minimum liability that was probable if the final judgment were to be consistent with the jury verdict.  While the judgment was being appealed, in May 2006 SCANA paid the plaintiff $11 million in settlement of its claims.  The Court’s procedural process for disposing of the litigation is underway.

         SCANA is also defending a claim for $2.7 million for reimbursement of legal fees and expenses under an indemnification and hold harmless agreement in the contract for the sale of the propane gas assets. A bench trial on the indemnification was held in January 2005, and in August 2005 an order was entered against SCANA in the amount of $2.6 million.  In December 2005, the judge vacated this award, and further motions to review his order are pending.  SCANA has made provision for this potential loss and further believes that the resolution of this claim will not have a material adverse impact on its results of operations, cash flows or financial condition.

In August 2003, SCE&G was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and SCE&G in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. Since that time, the plaintiffs have dismissed defendants Duke Energy and Progress Energy and are proceeding against SCE&G only. The plaintiffs are seeking damages for the alleged improper use of electric transmission and distribution easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to nonutility third parties or telecommunication companies for other than the electric utilities' internal use along the electric transmission and distribution line rights-of-way constitutes a trespass. It is anticipated that this case may go to trial in 2006. SCANA & SCE&G are confident of the propriety of SCE&G’s actions and intend to mount a vigorous defense. SCANA and SCE&G further believe that the resolution of these claims will not have a material adverse impact on their results of operations, cash flows or financial condition.

In May 2004, the Company was served with a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation. The case was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges the Company made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication 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 in June 2005. The plaintiff appealed to the South Carolina Supreme Court. The Supreme Court heard the appeal in May 2006, but has not announced a decision. The Company will continue 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 in October 2003 against SCE&G by the State of South Carolina alleging that SCE&G violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality’s limits. The complaint alleged that SCE&G failed to obey, observe or comply with the lawful order of the SCPSC by charging franchise fees to those not residing within a municipality. The complaint sought restitution to all affected customers and penalties of up to $5,000 for each separate violation. The State of South Carolina v. SCE&G claim has been settled by an agreement between the parties, and the settlement has been approved by South Carolina’s Circuit Court of Common Pleas for the Fifth Judicial Circuit. In addition, SCE&G filed a petition with the SCPSC in October 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.

D.     Other Contingency

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

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

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

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

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, Gas Distribution and Gas Transmission segments. The Company uses net income to measure profitability for its Retail Gas Marketing and Energy Marketing segments. Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy which meet SFAS 131 criteria for aggregation. All Other includes equity method investments and other nonreportable segments.

	External			Intersegment			Operating			Net			Segment
Millions of dollars	Revenue			Revenue			Income (Loss)			Income (Loss)			Assets
Three Months Ended June 30, 2006
Electric Operations	$	461		$	3		$	119			n/a
Gas Distribution		165			-			(7	)		n/a
Gas Transmission		50			72			8			n/a
Retail Gas Marketing		91			-			n/a		$	3
Energy Marketing		177			20			n/a			(1	)
All Other		13			79			n/a			1
Adjustments/Eliminations		(13	)		(174	)		2			55
Consolidated Total	$	944		$	-		$	122		$	58

Six Months Ended June 30, 2006
Electric Operations	$	859		$	4		$	210		n/a		$	5,458
Gas Distribution		611			-			54		n/a			1,648
Gas Transmission		119			225			16		n/a			324
Retail Gas Marketing		362			-			n/a	$	24			151
Energy Marketing		382			31			n/a		(1	)		91
All Other		29			154			n/a		(2	)		553
Adjustments/Eliminations		(29	)		(414	)		28		135			1,173
Consolidated Total	$	2,333		$	-		$	308	$	156		$	9,398

Three Months Ended June 30, 2005
Electric Operations	$	440		$	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	$	893		$	-		$	85		$	44

Six Months Ended June 30, 2005
Electric Operations	$	856		$	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	$	2,160		$	-		$	113	$	145		$	8,761

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

                 RESULTS OF OPERATIONS

SCANA CORPORATION

The following discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations appearing in SCANA Corporation’s (SCANA, and together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, 2005.

Statements included in this discussion and analysis (or elsewhere in this quarterly report) which are not statements of historical fact are intended to be, and are hereby identified as, “forward-looking statements” for purposes of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following: (1) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) regulatory actions or changes in the utility and nonutility regulatory environment, (3) current and future litigation, (4) changes in the economy, especially in areas served by subsidiaries of SCANA, (5) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (6) growth opportunities for SCANA’s regulated and diversified subsidiaries, (7) the results of financing efforts, (8) changes in accounting principles, (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.

RESULTS OF OPERATIONS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2006

AS COMPARED TO THE CORRESPONDING PERIODS IN 2005

Earnings Per Share

The Company's reported earnings are prepared in accordance with generally accepted accounting principles (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
	2006		2005		2006		2005
Reported (GAAP) earnings per share:	$	.50	$	.39	$	1.35	$	1.28
Deduct:
Cumulative effect of accounting change, net of tax		-		-		.05		-
Reduction in propane litigation accrual upon settlement		.04		-		.04		-
Realized gain from sale of telecommunications investment		-		.03		-		.03
GAAP-adjusted net earnings per share from operations	$	.46	$	.36	$	1.26	$	1.25

Discussion of adjustments

The cumulative effect of accounting change resulted from the Company’s adoption of Statement of Financial Accounting Standard (SFAS) 123 (revised 2004), “Share-Based Payment” (SFAS 123(R)). This reduction appears in the income statement as a reduction to other expenses. The reduction in propane litigation accrual resulted from the propane litigation being settled for an amount that was less than had been accrued in 2004. The realized gain from sale of 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 per share from operations increased primarily due to increases in electric margins of $.09 and increases in gas margins of $.02, partially offset by 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.

Year to Date

GAAP-adjusted net earnings per share from operations increased primarily due to increases in electric margins of $.07, and were partially offset by a decrease in gas margins of $.04 and the effects of dilution of $.02. Accelerated depreciation on the Lake Murray back-up dam and recognition of synthetic fuel tax credits and related items had no effect on net income, as discussed below.

Management believes that the adjustments are appropriate in determining the non-GAAP financial performance measure. Management utilizes such measure itself in exercising budgetary control, managing business operations and determining eligibility for incentive compensation payments. The non-GAAP measure, GAAP-adjusted net earnings per share from operations, provides a consistent basis upon which to measure performance by excluding the effects on per share earnings of the cumulative effect of the accounting change resulting from the Company’s adoption of SFAS 123(R), of litigation related to the sale of a prior business and of transactions involving the Company’s telecommunications investments.

Recognition of Synthetic Fuel Tax Credits

South Carolina Electric & Gas Company (SCE&G) holds equity-method investments in two partnerships involved in converting coal to synthetic fuel, the use of which fuel qualifies for federal income tax credits. Under an accounting plan approved by the Public Service Commission of South Carolina (SCPSC) in June 2000, the synthetic fuel tax credits generated by the partnerships and passed through to SCE&G, net of partnership losses and other expenses, were deferred until the SCPSC approved their application to offset capital costs of the Lake Murray back-up dam project. Under the accounting methodology approved by the SCPSC in a January 2005 order, construction costs related to the project were recorded in utility plant in service in a special dam remediation account, outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

The level of depreciation expense and related tax benefit recognized in the income statement 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 may decline as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, they can have a significant impact on individual line items within the income statement. In addition, SCE&G is allowed to record non-cash carrying costs on the unrecovered investment, which is described further at Other Income. See also Regulatory Matters-Synthetic Fuel.The accelerated depreciation, synthetic fuel tax credits, partnership losses and the income tax benefit arising from such losses recognized by SCE&G during the three and six months ended June 30, 2006 and 2005 are as follows:

	Second Quarter						Year to Date
Millions of dollars	2006			2005			2006			2005
Depreciation and amortization expense	$	(1.2	)	$	(13.9	)	$	(1.4	)	$	(183.6	)
Income tax benefits:
From synthetic fuel tax credits		3.3			11.2			6.6			155.2
From accelerated depreciation		0.5			5.3			0.6			70.2
From partnership losses		1.5			1.6			3.5			25.9
Total income tax benefits		5.3			18.1			10.7			251.3
Losses from Equity Method Investments		(4.1	)		(4.2	)		(9.3	)		(67.7	)
Impact on Net Income	$	-		$	-		$	-		$	-

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

Pension Income

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

	Second Quarter				Year to Date
Millions of dollars	2006		2005		2006		2005
Income Statement Impact:
Reduction in employee benefit costs	$	0.2	$	1.2	$	0.4	$	2.3
Other income		3.0		3.0		6.1		6.0
Balance Sheet Impact:
Reduction in capital expenditures		0.1		0.3		0.2		0.7
Component of amount due to Summer Station co-owner		0.1		0.1		0.1		0.3
Total Pension Income	$	3.4	$	4.6	$	6.8	$	9.3

For the last several years, the market value of the Company’s retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. Pension income for the second quarter and year to date 2006 decreased compared to the corresponding periods in 2005, primarily as a result of investment returns.

Other Income

Included in other income is an allowance for funds used during construction (AFC). AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income.

Also included in other income for the three and six months ended June 30, 2006 is a recovery of carrying costs through synthetic fuel tax credits of $2.0 million and $4.0 million, respectively, which was recorded under provisions of the January 2005 SCPSC rate order. The amounts for the corresponding periods ended June 30, 2005, were $3.0 million and $6.0 million, respectively.

Dividends Declared

The Company’s Board of Directors has declared the following dividends on common stock during 2006:

Declaration Date	Dividend Per Share	Record Date	Payment Date
February 16, 2006	$.42	March 10, 2006	April 1, 2006
April 27, 2006	$.42	June 9, 2006	July 1, 2006
August 3, 2006	$.42	September 11, 2006	October 1, 2006

Electric Operations

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

	Second Quarter							Year to Date
Millions of dollars	2006		% Change			2005		2006		% Change			2005
Operating revenues	$	460.8		4.9	%	$	439.2	$	859.5		0.4	%	$	855.9
Less: Fuel used in generation		146.6		6.9	%		137.2		264.1		(0.3	)%		265.0
Purchased power		8.2		(34.4	)%		12.5		11.9		(42.2	)%		20.6
Margin	$	306.0		5.7	%	$	289.5	$	583.5		2.3	%	$	570.3

Second Quarter

Margin increased by $9.6 million due to favorable weather, by $6.8 million due to customer growth and by $2.8 million due to off-system sales.

Year to Date

Margin increased by $12.7 million due to customer growth and by $5.2 million in increased off-system sales, offset primarily by $2.4 million due to unfavorable weather in the first quarter.

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	2006		% Change			2005		2006		% Change			2005
Operating revenues	$	165.4		(1.9	)%	$	168.6	$	611.2		7.0	%	$	571.4
Less: Gas purchased for resale		121.0		(2.5	)%		124.1		456.7		9.5	%		417.0
Margin	$	44.4		(0.2	)%	$	44.5	$	154.5		0.1	%	$	154.4

Second Quarter

Margin remained flat, with a $1.2 million increase due to retail base rates at SCE&G which became effective with the first billing cycle in November 2005, by $1.6 million due to higher firm margin, by $0.8 million due to other revenue and customer growth of 4% at PSNC Energy, offset by milder weather and the effects of customer conservation efforts, primarily at PSNC Energy.

Year to Date

Margin remained flat, with a $8.2 million increase due to retail base rates at SCE&G which became effective with the first billing cycle in November 2005 and customer growth of 4% at PSNC Energy, offset by milder weather and the effects of customer conservation efforts, primarily at PSNC Energy, and $2.6 million due to winter assistance credits at SCE&G.

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	2006		% Change			2005		2006		% Change			2005
Operating revenues	$	121.8		(0.1	)%	$	121.9	$	343.6		13.4	%	$	302.9
Less: Gas purchased for resale		107.3		(2.4	)%		109.9		313.8		13.8	%		275.8
Margin	$	14.5		20.8	%	$	12.0	$	29.8		10.0	%	$	27.1

Second Quarter

      Margin increased by $0.8 million due to increased revenue from capacity charges, by $1.2 million due to higher industrial margin and by $0.5 million due to higher interruptible transportation revenue.

Year to Date

       Margin increased by $ 1.7 million due to increased revenue from capacity charges, by $0.3 million due to higher industrial margin and by $0.7 million due to higher interruptible transportation revenue.

Retail Gas Marketing

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

	Second Quarter							Year to Date
Millions of dollars	2006		% Change			2005		2006		% Change			2005
Operating revenues	$	91.2		(0.8	)%	$	91.9	$	362.1		9.5	%	$	330.8
Net income	$	2.3		*		$	1.0	$	23.7		1.3	%	$	23.4

*Greater than 100%

Second Quarter

Operating revenues decreased primarily as a result of higher average retail prices due to higher commodity gas costs being more than offset by lower customer usage.Net income increased primarily due to higher sales margins.

Year to Date

Operating revenues increased primarily as a result of higher average retail prices due to higher commodity gas costs. Net income increased due to lower bad debt expenses and operating expense primarily in the first quarter, which were partially offset by lower sales margins.

Energy Marketing

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

	Second Quarter									Year to Date
Millions of dollars	2006			% Change			2005			2006			% Change			2005
Operating revenues	$	197.8			18.8	%	$	166.5		$	413.4			22.7	%	$	337.0
Net loss	$	(0.6	)		*		$	(0.2	)	$	(0.6	)		45.5	%	$	(1.1	)

*Greater than 100%

Second Quarter

Operating revenues increased primarily as a result of higher commodity prices and increased volumes. Net loss increased primarily due to lower margins.

Year to Date

Operating revenues increased primarily as a result of higher commodity prices and increased volumes. Net loss decreased primarily due to lower operating expenses.

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	2006		% Change			2005		2006		% Change			2005
Other operation and maintenance	$	150.1		(1.7	)%	$	152.7	$	306.6		(1.6	)%	$	311.6
Depreciation and amortization		77.1		(13.4	)%		89.0		153.3		(54.1	)%		333.8
Other taxes		37.2		(6.5	)%		39.8		75.9		(2.7	)%		78.0
Total	$	264.4		(6.1	)%	$	281.5	$	535.8		(25.9	)%	$	723.4

Second Quarter

Other operation and maintenance expenses decreased due to lower labor costs due to lower incentive compensation accruals, partially offset by increased electric generation, transmission and distribution expenses. Depreciation and amortization decreased $12.5 million due to accelerated depreciation of the back-up dam at Lake Murray in 2005 (previously explained at Recognition of Synthetic Fuel Tax Credits) and the lower levels of credits recognized in 2006 due to applicability of the phase-down provisions previously discussed.

Year to Date

Other operation and maintenance expenses decreased due to lower labor costs due to lower incentive compensation accruals and due to lower operating, marketing and customer service expenses, primarily in the first quarter, in Retail Gas Marketing. These decreases were partially offset by increased electric generation, transmission and distribution expenses. Depreciation and amortization decreased $182.2 million due to accelerated depreciation of the back-up dam at Lake Murray in 2005 (previously explained at Recognition of Synthetic Fuel Tax Credits) and the lower levels of credits recognized in 2006 due to applicability of the phase-down provisions previously discussed.

Income Taxes

Income tax expense for the six months ended June 30, 2006 increased primarily due to the initial application and recognition of synthetic fuel tax credits in the first quarter of 2005, and the phase down in 2006, as previously discussed at Recognition of Synthetic Fuel Tax Credits.  In addition, other tax credits of $2.0 million were recorded in the first quarter of 2005. 

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, 2006 was 3.04.

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

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

SCE&G expects to require the addition of base load electrical generation by 2015 and is evaluating alternatives, including fossil- and nuclear-fueled generation. On February 10, 2006, SCE&G and Santee Cooper, a state-owned utility in South Carolina (joint owners of Summer Station) announced their selection of the Summer Station site as the preferred site for new nuclear generation should such generation be considered the best alternative in the future. Due to the significant lead time required for construction of nuclear generation, the joint owners are preparing an application to the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL) that would cover two new nuclear units. The COL application, which is expected to be completed and filed in 2007, would be reviewed by the NRC for an estimated three years. Issuance of a COL would not obligate the joint owners to build nuclear generation. The final decision to build nuclear generation will be influenced by several factors, including NRC licensing attainment, construction and operating costs, the cost of competing fuels, regulatory and environmental requirements and financial market conditions.

The following table summarizes how the Company generated and used funds for property additions and construction expenditures during the six months ended June 30, 2006 and 2005:

	Six Months Ended
	June 30,
Millions of dollars	2006			2005
Net cash provided from operating activities	$	469		$	333
Net cash provided from (used for) financing activities		(123	)		(67	)
Cash provided from sale of investment and assets		18			6
Cash and cash equivalents available at the beginning of the period		62			120
Funds used for utility property additions and construction expenditures		(224	)		(212	)
Funds used for nonutility property additions		(21	)		(7	)
Funds used for investments		(21	)		(27	)

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

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

In June 2006 SCE&G issued $125 million of first mortgage bonds having an annual interest rate of 6.25% and maturing July 1, 2036. The proceeds from the sale of these bonds, together with available cash, were used for the payment at maturity of $131 million of SCE&G’s first and refunding mortgage bonds due July 15, 2006, which bore interest at 9.0%.

ENVIRONMENTAL MATTERS

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

REGULATORY MATTERS

Carolina Gas Transmission Corporation

On July 20, 2006, FERC approved the application for merger of SCG Pipeline, Inc, into SCPC, both SCANA subsidiaries, to form Carolina Gas Transmission Corporation (CGTC). CGTC will operate as an open access transportation-only interstate pipeline company. SCANA expects that the merger will be finalized and that CGTC will commence operations by October 1, 2006.

Synthetic Fuel

SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel, the use of which fuel qualifies for federal income tax credits. In a January 2005 order, the SCPSC approved SCE&G’s request to apply these tax credits, net of partnership losses and other expenses, to offset the construction costs of the Lake Murray back-up dam project. Under the accounting methodology approved by the SCPSC, construction costs related to the project were recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

The level of depreciation expense and related income tax benefit recognized in the income statement is equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of taxes. As a result, the balance of unrecovered costs in the dam remediation account may decline 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 back-up dam remediation account will be matched to available synthetic fuel tax credits on a quarterly basis until the balance in the dam remediation account is zero or until all of the available synthetic fuel tax credits have been utilized. Under current law, the synthetic fuel tax credit program expires at the end of 2007.

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

The benchmark price range for 2005, published in April 2006, is $53 to $67 per barrel, and no phase-out applied. However, SCE&G’s analysis indicates that the available synthetic fuel tax credits for 2006 are likely to be impacted by the phase-out calculation. As such, through June 2006 the Company recorded synthetic fuel tax credits and applied those credits to allow the recording of accelerated depreciation related to the balance in the dam remediation project account based on an estimate that only 38 percent of credits generated will be available (phase-out of 62 percent). The Company cannot predict what impact, if any, the price of oil may have on the Company’s ability to earn and utilize synthetic fuel tax credits in the future. However, there is significant uncertainty as to the continued availability of the credits in 2006 and 2007. The availability of these synthetic fuel tax credits is also subject to coal availability and other operational risks related to the generating plants.

If it is determined that available credits are not sufficient to fully recover the construction costs of the dam remediation, regulatory action to allow recovery of those remaining costs may be sought. As of June 30, 2006, remaining unrecovered costs, based on management’s recording of accelerated depreciation and related tax benefits, were $92.3 million.

Finally, Primesouth, Inc., a subsidiary of SCANA, provides management and maintenance services for a non-affiliated synthetic fuel production facility. Reduced synthetic fuel tax credit availability under the above phase-out provisions also adversely impacts the level of payment Primesouth receives for these services. The fees recognized by Primesouth in both the second quarter and year to date periods ended June 30, 2006 were $5.2 million lower than amounts recognized in the second quarter and year to date periods ended June 30, 2005.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

As of June 30, 2006			Expected Maturity Date
Millions of dollars
						There-		Fair
Liabilities	2006	2007	2008	2009	2010	After	Total	Value
Long-Term Debt:
Fixed Rate ($)	135.7	68.6	158.6	143.6	50.3	2,643.0	3,199.8	3,233.8
Average Fixed Interest Rate (%)	8.95	6.96	6.13	6.39	6.79	6.15	6.30	n/a
Variable Rate ($)			100.0				100.0	100.0
Average Variable Interest Rate (%)			5.38				5.38	n/a
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)	-	28.2	3.2	3.2	3.2	6.4	44.2	(0.2)
Average Pay Interest Rate (%)	-	8.76	8.69	8.69	8.69	8.69	8.74	n/a
Average Receive Interest Rate (%)	-	7.11	8.75	8.75	8.75	8.75	7.70	n/a

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

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

Expected Maturity:
				Options
	Futures Contracts			Purchased Call	Sold Put
2006	Long	Short		(Long)	(Long)
Settlement Price (a)	7.74	8.68	Strike Price (a)	8.50	7.02
Contract Amount (b)	21.2	2.1	Contract Amount	6.6	0.6
Fair Value (b)	19.3	1.9	Fair Value	0.8	-
2007
Settlement Price (a)	9.88	10.40	Strike Price (a)	-	-
Contract Amount (b)	19.1	3.1	Contract Amount	-	-
Fair Value (b)	19.4	3.1	Fair Value	-	-
(a)   Weighted average, in dollars
(b)  Millions of dollars

Swaps	2006	2007
Commodity Swaps:
Pay fixed/receive variable (b)	72.7	67.1
Average pay rate (a)	8.8991	9.9084
Average received rate (a)	7.5828	9.8852
Fair value (b)	62.0	67.0
Pay variable/receive fixed (b)	0.8	-
Average pay rate (a)	7.7988	-
Average received rate (a)	10.3635	-
Fair value (b)	1.0	-
Basis Swaps:
Pay variable/receive variable (b)	23.5	-
Average pay rate (a)	6.3935	-
Average received rate (a)	6.4027	-
Fair value (b)	23.6	-
(a)   Weighted average, in dollars
(b)  Millions of dollars

SOUTH CAROLINA ELECTRIC & GAS COMPANY

FINANCIAL SECTION

ITEM 1. FINANCIAL STATEMENTS

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,			December 31,
Millions of dollars	2006			2005
Assets
Utility Plant In Service	$	7,779		$	7,687
Accumulated Depreciation and Amortization		(2,355	)		(2,285	)
		5,424			5,402
Construction Work in Progress		201			160
Nuclear Fuel, Net of Accumulated Amortization		41			28
Utility Plant, Net		5,666			5,590
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation		30			28
Assets held in trust, net - nuclear decommissioning		52			52
Other investments		29			28
Nonutility Property and Investments, Net		111			108
Current Assets:
Cash and cash equivalents		13			19
Receivables, net of allowance for uncollectible accounts of $2 and $2		331			366
Receivables - affiliated companies		22			32
Inventories (at average cost):
Fuel		67			62
Materials and supplies		81			72
Emission allowances		20			7
Prepayments and other		24			12
Deferred income taxes		23			22
Total Current Assets		581			592
Deferred Debits and Other Assets:
Pension asset, net		310			303
Due from affiliates - pension and postretirement benefits		25			31
Emission allowances		32			47
Regulatory assets		546			584
Other		123			121
Total Deferred Debits and Other Assets		1,036			1,086
Total	$	7,394		$	7,376

	June 30,		December 31,
Millions of dollars	2006		2005
Capitalization and Liabilities
Shareholders’ Investment:
Common equity	$	2,387	$	2,362
Preferred stock (Not subject to purchase or sinking funds)		106		106
Total Shareholders’ Investment		2,493		2,468
Preferred Stock, net (Subject to purchase or sinking funds)		8		8
Long-Term Debt, net		1,981		1,856
Total Capitalization		4,482		4,332
Minority Interest		85		82
Current Liabilities:
Short-term borrowings		215		303
Current portion of long-term debt		183		183
Accounts payable		99		84
Accounts payable - affiliated companies		82		142
Customer deposits and customer prepayments		38		35
Taxes accrued		93		140
Interest accrued		34		35
Dividends declared		41		40
Other		22		38
Total Current Liabilities		807		1,000
Deferred Credits and Other Liabilities:
Deferred income taxes, net		815		801
Deferred investment tax credits		119		119
Asset retirement obligations		317		309
Postretirement benefits		152		148
Due to affiliates - pension and postretirement benefits		12		12
Regulatory liabilities		531		498
Other		74		75
Total Deferred Credits and Other Liabilities		2,020		1,962
Commitments and Contingencies (Note 4)		-		-
Total	$	7,394	$	7,376

See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Millions of dollars	2006			2005			2006			2005
Operating Revenues:
Electric	$	464		$	440		$	864		$	858
Gas		89			85			281			242
Total Operating Revenues		553			525			1,145			1,100
Operating Expenses:
Fuel used in electric generation		147			137			264			265
Purchased power		8			13			12			21
Gas purchased for resale		72			71			225			192
Other operation and maintenance		114			112			229			221
Depreciation and amortization		65			78			130			311
Other taxes		34			36			69			71
Total Operating Expenses		440			447			929			1,081
Operating Income		113			78			216			19
Other Income (Expense):
Other income		5			25			44			60
Other expenses		(1	)		(20	)		(36	)		(52	)
Allowance for equity funds used during construction		-			2			-			5
Interest charges, net of allowance for borrowed funds
used during construction of $2, $1, $3 and $1		(36	)		(37	)		(72	)		(74	)
Gain on sale of assets		-			1			-			1
Total Other Expense		(32	)		(29	)		(64	)		(60	)
Income (Loss) Before Income Taxes (Benefit), Losses from Equity
Method Investments, Minority Interest, Cumulative Effect of
Accounting Change and Preferred Stock Dividends		81			49			152			(41	)
Income Tax Expense (Benefit)		23			3			41			(205	)
Income Before Losses from Equity Method Investments,
Minority Interest, Cumulative Effect of Accounting Change
and Preferred Stock Dividends		58			46			111			164
Losses from Equity Method Investments		(4	)		(5	)		(10	)		(69	)
Minority Interest		1			1			3			3
Cumulative Effect of Accounting Change, net of taxes		-			-			4			-
Net Income		53			40			102			92
Preferred Stock Cash Dividends Declared		2			2			4			4
Earnings Available for Common Shareholder	$	51		$	38		$	98		$	88
See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
Millions of dollars	2006			2005
Cash Flows From Operating Activities:
Net income	$	102		$	92
Adjustments to Reconcile Net Income to Net Cash Provided From Operating Activities:
Cumulative effect of accounting change, net of taxes		(4	)		-
Losses from equity method investments		10			69
Minority interest		3			3
Depreciation and amortization		130			310
Amortization of nuclear fuel		9			8
Gain on sale of assets		-			(1	)
Carrying cost recovery		(4	)		(6	)
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		41			(53	)
Inventories		(28	)		(75	)
Prepayments		(11	)		4
Pension asset		(7	)		(9	)
Other regulatory assets		11			23
Deferred income taxes, net		13			(38	)
Regulatory liabilities		18			(144	)
Postretirement benefits		4			3
Accounts payable		(41	)		(24	)
Taxes accrued		(47	)		(65	)
Interest accrued		(1	)		(1	)
Changes in fuel adjustment clauses		29			(9	)
Changes in other assets		11			(6	)
Changes in other liabilities		(1	)		(9	)
Net Cash Provided From Operating Activities		237			72
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(181	)		(182	)
Proceeds from sale of assets		-			1
Investments		(17	)		(9	)
Net Cash Used For Investing Activities		(198	)		(190	)
Cash Flows From Financing Activities:
Proceeds from issuance of debt		123			97
Repayment of debt		(8	)		(253	)
Redemption of preferred stock		-			(1	)
Dividends on equity securities		(79	)		(78	)
Contribution from parent		3			59
Short-term borrowings - affiliate, net		4			(2	)
Short-term borrowings, net		(88	)		293
Net Cash Provided From (Used For) Financing Activities		(45	)		115
Net Increase (Decrease) In Cash and Cash Equivalents		(6	)		(3	)
Cash and Cash Equivalents, January 1		19			20
Cash and Cash Equivalents, June 30	$	13		$	17
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $3 and $1)		7			71
- Income taxes		31			23
Noncash Investing and Financing Activities:
Accrued construction expenditures		14			13
See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2006

(Unaudited)

The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in South Carolina Electric & Gas Company’s (SCE&G, and together with its consolidated affiliates, the Company) Annual Report on Form 10-K for the year ended December 31, 2005. These are interim financial statements, and due to the seasonality of the Company’s business and matters that may occur during the rest of the year, the amounts reported in the Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the full year. In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature, which are necessary for a fair statement of the results for the interim periods reported.

1.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.   Variable Interest Entity

Financial Accounting Standards Board Interpretation (FIN) 46 (Revised 2003), “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 power purchase and related operating agreements. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and sulfur dioxide emission allowances. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of $256 million) serves as collateral for its long-term borrowings.

B.    Basis of Accounting

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

	June 30,		December 31,
Millions of dollars	2006		2005
Regulatory Assets:
Accumulated deferred income taxes	$	170	$	170
Under-collections - electric fuel and gas cost adjustment clauses		16		56
Purchased power costs		13		17
Environmental remediation costs		19		18
Asset retirement obligations and related funding		250		240
Franchise agreements		56		56
Regional transmission organization costs		9		11
Other		13		16
Total Regulatory Assets	$	546	$	584

Regulatory Liabilities:
Accumulated deferred income taxes	$	35	$	36
Other asset removal costs		420		404
Storm damage reserve		42		38
Planned major maintenance		18		9
Other		16		11
Total Regulatory Liabilities	$	531	$	498

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, 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.

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

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 $18.5 million remain to be recovered.

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

Franchise agreements represent costs associated with 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 and are expected to be fully amortized over approximately 20 years.

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

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

The storm damage reserve represents an SCPSC approved reserve account capped at $50 million to be collected through rates. The accumulated 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, 2006, no amounts were drawn from this reserve account.

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

The SCPSC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not approved for recovery by the SCPSC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by SCE&G. However, ultimate recovery is subject to SCPSC approval. In the future, as a result of 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. SCE&G purchases natural gas for resale and for electric generation from South Carolina Pipeline Corporation (SCPC) and had $21.9 million and $72.1 million payable to SCPC for such gas purchases at June 30, 2006 and December 31, 2005, respectively.

SCE&G purchases natural gas and related pipeline capacity to supply its Jasper County Electric Generating Station from SCANA Energy Marketing, Inc. (SEMI). Such purchases totaled $16.3 million and $23.3 million for the three and six months ended June 30, 2006, respectively and totaled $25.2 million and $45.4 million for the three and six months ended June 30, 2005, respectively. SCE&G had $10.2 million and $8.0 million payable to SEMI for such purposes as of June 30, 2006 and December 31, 2005, respectively.

SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel. The Company’s receivables from these affiliated companies were $21.6 million and $24.6 million at June 30, 2006 and December 31, 2005, respectively. SCE&G’s payables to these affiliated companies were $22.0 million and $25.3 million at June 30, 2006 and December 31, 2005, respectively. SCE&G purchased $64.5 million and $62.8 million of synthetic fuel from these affiliated companies for the three months ended June 30, 2006 and 2005, respectively. SCE&G purchased $129.2 million and $113.7 million of synthetic fuel from these affiliated companies for the six months ended June 30, 2006 and 2005, respectively.

In the six months ended June 30, 2005, the Company purchased 342 miles of gas distribution pipeline from SCPC at its net book value, which totaled $20.7 million.

D.      Pension and Other Postretirement Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2006			2005			2006			2005
Three months ended June 30,
Service cost	$	3.5		$	3.1		$	1.2		$	0.9
Interest cost		9.9			9.5			2.8			2.8
Expected return on assets		(18.8	)		(19.1	)		-			-
Prior service cost amortization		1.7			1.7			0.2			0.3
Transition obligation amortization		0.1			0.2			0.2			0.2
Amortization of actuarial loss		0.2			-			0.4			0.4
Amount attributable to Company affiliates		(0.6	)		(0.5	)		(1.3	)		(1.3	)
Net periodic benefit (income) cost	$	(4.0	)	$	(5.1	)	$	3.5		$	3.3

Six months ended June 30,
Service cost	$	7.0		$	6.1		$	2.4		$	1.8
Interest cost		19.8			19.0			5.6			5.6
Expected return on assets		(37.6	)		(38.2	)		-			-
Prior service cost amortization		3.4			3.4			0.4			0.6
Transition obligation amortization		0.2			0.4			0.4			0.4
Amortization of actuarial loss		0.4			-			0.7			0.8
Amount attributable to Company affiliates		(1.2	)		(0.9	)		(2.6	)		(2.6	)
Net periodic benefit (income) cost	$	(8.0	)	$	(10.2	)	$	6.9		$	6.6

E.      Share-Based Compensation

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

SFAS 123 (revised 2004),“Share-Based Payment” (SFAS 123(R)), requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) replaces SFAS 123, “Accounting for Stock-Based Compensation” and supersedes Accounting Principles Board (APB) Opinion 25, “Accounting for Stock Issued to Employees.” The cumulative effect of the adoption of SFAS 123(R) on January 1, 2006 resulted in a $4 million (net of tax) gain in the first quarter of 2006 based on a reduction of prior compensation accruals for performance awards (discussed below) granted in 2004 and 2005.

Liability Awards

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

Under SFAS 123(R) compensation cost of these liability awards is recognized over the three-year performance period based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Cash-settled liabilities totaling $1.2 million were paid during the six months ended June 30, 2006. No such payments were made during the corresponding period in 2005.

Fair value adjustments for performance awards resulted in a reduction to compensation expense recognized in the condensed statements of income, exclusive of the cumulative effect adjustment discussed previously, totaling $(1.2) million and $(0.5) million for the three and six months ended June 30, 2006, respectively, and an increase to compensation expense totaling $1.8 and $3.1 million for the corresponding periods ended June 30, 2005, respectively. Fair value adjustments resulted in no net compensation costs being capitalized during the six months ended June 30, 2006, compared with approximately $0.5 million of net compensation costs being capitalized during the corresponding period in 2005.

Equity Awards

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

	Number of Options	Weighted Average Exercise Price
Outstanding-December 31, 2005	439,270	$27.53
Exercised	(11,341)	$27.12
Outstanding-March 31, 2006	427,929	$27.48
Exercised	(6,805)	$27.48
Outstanding-June 30, 2006	421,124	$27.54

No stock options have been granted since August 2002, and all options were fully vested in August 2005. The options expire ten years after the grant date. At June 30, 2006, all outstanding options were currently exercisable at prices ranging from $25.50-$29.60, and had a weighted-average remaining contractual life of 5.4 years.

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

All options were granted with exercise prices equal to the fair market value of SCANA’s common stock on the respective grant dates; therefore, no compensation expense was recognized in connection with such grants. If the Company had recognized compensation expense for the issuance of options based on the fair value method described in SFAS 123(R), pro forma earnings available for the common shareholder would have been unchanged from that reported for the three and six months ended June 30, 2005.

F.      New Accounting Matters

The Company adopted SFAS 154, “Accounting Changes and Error Corrections,” in the first quarter of 2006. SFAS 154 requires retrospective application to financial statements of prior periods for every voluntary change in accounting principle unless such retrospective application is impracticable. SFAS 154 replaces APB 20, “Accounting Changes,” and SFAS 3, “Reporting Accounting Changes in Interim Financial Statements,” although it carries forward some of their provisions. The adoption of SFAS 154 had no material impact on the Company’s results of operations, cash flows or financial position.

SFAS 123(R), requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) replaces SFAS 123, “Accounting for Stock-Based Compensation” and supersedes APB 25, “Accounting for Stock Issued to Employees.” The Company adopted SFAS 123(R) in the first quarter of 2006. The impact on the Company’s results of operations is discussed at Note 1E.

FIN 48, “Accounting for Uncertainty in Income Taxes,” was issued in June 2006. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company will adopt FIN 48 in the first quarter of 2007. The Company is continuing to evaluate the impact that adoption of FIN 48 may have 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 2006.

2.      RATE AND OTHER REGULATORY MATTERS

Electric

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 was as follows:

Rate Per KWh	Effective Date
$.01764	January-April 2005
$.02256	May 2005-April 2006
$.02516	May-June 2006

In connection with the May 2006 fuel component increase, SCE&G agreed to spread the recovery of previously under-collected fuel costs of $38.5 million over a two-year period.

Gas

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

In June 2006, SCE&G reported to the SCPSC that its return on common equity for the twelve months ended March 31, 2006 was 4.38 percent, compared to an allowed return of 10.25 percent. Since the actual return was more than 0.5 percent below the allowed return, and as provided under South Carolina’s Natural Gas Rate Stabilization Act, SCE&G requested an annualized increase in certain natural gas base rates of 3.3 percent, or $18 million. If approved by the SCPSC, this request would return SCE&G’s regulatory return on common equity to the 10.25 percent authorized level. If approved, the rate adjustment would be effective with the first billing cycle in November 2006.

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 for residential, small and medium general service and large general service classes were as follows (rate per therm):

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

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

3.      LONG-TERM DEBT

In June 2006 SCE&G issued $125 million of first mortgage bonds having an annual interest rate of 6.25% and maturing July 1, 2036. The proceeds from the sale of these bonds, together with available cash, were used for the payment at maturity of $131 million of SCE&G’s first and refunding mortgage bonds due July 15, 2006, which bore interest at 9.0%.

In anticipation of the issuance of debt, the Company uses interest rate lock or similar agreements to manage interest rate risk. Payments received or made upon termination of such agreements are recorded within long-term debt on the balance sheet and are amortized to interest expense over the term of the underlying debt. In connection with the issuance of first mortgage bonds in June 2006, SCE&G received approximately $8.8 million upon the termination of a treasury lock agreement. These proceeds will be amortized over the life of the related debt, thereby reducing its effective interest rate.

4.    COMMITMENTS AND CONTINGENCIES

Reference is made to Note 10 to the consolidated financial statements appearing in SCE&G’s Annual Report on Form 10-K for the year ended December 31, 2005. Commitments and contingencies at June 30, 2006 include the following:

A.    Nuclear Insurance

The Price-Anderson Indemnification Act deals with public liability for a nuclear incident and establishes the liability limit for third-party claims associated with any nuclear incident at $10.5 billion. Each reactor licensee is currently liable for up to $100.6 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $15 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station, would be $67.1 million per incident, but not more than $10 million per year.

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property 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 $15.6 million.

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

B.    Environmental

In March 2005, the Environmental Protection Agency (EPA) issued a final rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. SCE&G has petitioned the United States Court of Appeals for the District of Columbia Circuit to review CAIR. Several other electric utilities have filed separate petitions. The petitioners seek a change in the method CAIR uses to allocate sulfur dioxide emission allowances to a method the petitioners believe is more equitable. The Company believes that installation of additional air quality controls will be needed to meet the CAIR requirements. The Company is reviewing the final rule. Compliance plans and cost to comply with the rule will be determined once the Company completes its review. Such costs may 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. Although the Company expects to be able to meet the Phase I limits through those measures it already will be taking to meet its CAIR obligations, it is uncertain as to how the Phase II limits will be met. Assuming Phase II limits remain unchanged, installation of additional air quality controls likely will be required to comply with the rule’s Phase II mercury emission caps. Final compliance plans and costs to comply with the rule are still under review. Such costs will be material and are expected to be recoverable through rates.

 SCE&G has been named, along with 29 others, by the EPA as a potentially responsible party (PRP) at the Carolina Transformer Superfund site located in Fayetteville, North Carolina.  The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from 1967 to 1984.  During that time, SCE&G occasionally used CTC for the repair of existing transformers and the purchase of new transformers.  In 1984, EPA initiated a cleanup of PCB-contaminated soil and groundwater at the site.  EPA reports that it has spent $36 million to date.  SCE&G’s records indicate that only minimal quantities of used transformers were shipped to CTC, and it is not clear if any contained PCB-contaminated oil.  Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G is expected to be recoverable through rates.

SCE&G has been named, along with 53 others, by the EPA as a PRP at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia.  The EPA placed the site on the National Priorities List on April 19, 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned.  While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels.  During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils.  EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The site has not been cleaned up nor has a cleanup cost been estimated.  Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site is 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 $18.5 million at June 30, 2006. The deferral includes the estimated costs associated with the following matters.

SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. SCE&G anticipates that remediation for contamination at the site will be completed in late 2006, with certain monitoring and retreatment activities continuing until 2011. As of June 30, 2006, SCE&G had spent $21.7 million to remediate the site and expects to spend an additional $1.7 million prior to entering a monitoring and reporting stage. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to this site. Any cost arising from the remediation of this site is expected to be recoverable through rates.

SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. One of the sites has been remediated and will undergo routine monitoring until released by the South Carolina Department of Health and Environmental Control (DHEC). The other sites are currently being investigated under work plans approved by DHEC. SCE&G anticipates that major remediation activities for the three sites will be completed in 2010. As of June 30, 2006, SCE&G had spent $4.6 million related to these three sites, and expects to spend an additional $11.5 million. Any cost arising from the remediation of these sites is expected to be recoverable through rates.

C.   Claims and Litigation

In August 2003, SCE&G was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and SCE&G in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. Since that time, the plaintiffs have dismissed defendants Duke Energy and Progress Energy and are proceeding against SCE&G only. The plaintiffs are seeking damages for the alleged improper use of electric transmission and distribution easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to nonutility third parties or telecommunication companies for other than the electric utilities' internal use along the electric transmission and distribution line rights-of-way constitutes a trespass. It is anticipated that this case may go to trial in 2006. SCE&G is confident of the propriety of its actions and intends to mount a vigorous defense. SCE&G 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.

In May 2004, the Company was served with a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation. The case was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges the Company made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication 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 in June 2005. The plaintiff appealed to the South Carolina Supreme Court. The Supreme Court heard the appeal in May 2006, but has not announced a decision. The Company will continue 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 in October 2003 against SCE&G by the State of South Carolina alleging that SCE&G violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality’s limits. The complaint alleged that SCE&G failed to obey, observe or comply with the lawful order of the SCPSC by charging franchise fees to those not residing within a municipality. The complaint sought restitution to all affected customers and penalties of up to $5,000 for each separate violation. The State of South Carolina v. SCE&G claim has been settled by an agreement between the parties, and the settlement has been approved by South Carolina’s Circuit Court of Common Pleas for the Fifth Judicial Circuit. In addition, SCE&G filed a petition with the SCPSC in October 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.

D. Other Contingency

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

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

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

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

5.      SEGMENT OF BUSINESS INFORMATION

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

						Earnings (Loss)
			Operating			Available to
	External		Income			Common		Segment
Millions of Dollars	Revenue		(Loss)			Shareholder		Assets
Three Months Ended June 30, 2006
Electric Operations	$	464	$	119			n/a
Gas Distribution		89		(3	)		n/a
All Other		-		-			-
Adjustments/Eliminations		-		(3	)		51
Consolidated Total	$	553	$	113		$	51

Six Months Ended June 30, 2006
Electric Operations	$	864	$	210			n/a		$	5,458
Gas Distribution		281		16			n/a			404
All Other		-		-		$	(6	)		5
Adjustments/Eliminations		-		(10	)		104			1,527
Consolidated Total	$	1,145	$	216		$	98		$	7,394

Three Months Ended June 30, 2005
Electric Operations	$	440	$	83			n/a
Gas Distribution		85		(5	)		n/a
All Other		-		-			(5	)
Adjustments/Eliminations		-		-			43
Consolidated Total	$	525	$	78		$	38

Six Months Ended June 30, 2005
Electric Operations	$	857	$	8			n/a		$	5,287
Gas Distribution		242		12			n/a			381
All Other		-		-			(69	)		3
Adjustments/Eliminations		-		(1	)		157			1,301
Consolidated Total	$	1,099	$	19		$	88		$	6,972

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

                AND RESULTS OF OPERATIONS

SOUTH CAROLINA ELECTRIC & GAS COMPANY

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, 2005.

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

RESULTS OF OPERATIONS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2006

AS COMPARED TO THE CORRESPONDING PERIODS IN 2005

Net Income

Net income was as follows:

	Second Quarter		Year to Date
Millions of dollars	2006	2005	2006	2005
Net income	$52.5	$39.9	$102.0	$92.0

Second Quarter

Net income increased primarily due to increases in electric and gas margins of $12.0 million and $2.0 million, respectively, partially offset by increased operating and maintenance expenses of $0.8 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 increased primarily due to increases in electric and gas margins of $9.9 million and $4.0 million, respectively, and by $3.8 million due to the favorable impact of the cumulative effect of an accounting change resulting from the Company’s adoption of Statement of Financial Accounting Standard (SFAS) 123 (revised 2004), “Share-Based Payment” (SFAS 123(R)). See Note 1E of the condensed consolidated financial statements. Increases in electric and gas margins were offset by increased electric generation, transmission and operating expenses of $3.6 million and other expenses of $2.0 million. In addition, other tax credits of $2.0 million were recorded in the first quarter of 2005.  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. Under an accounting plan approved by the Public Service Commission of South Carolina (SCPSC) in June 2000, the synthetic fuel tax credits generated by the partnerships and passed through to SCE&G, net of partnership losses and other expenses, were deferred until the SCPSC approved their application to offset capital costs of the Lake Murray back-up dam project. Under the accounting methodology approved by the SCPSC in a January 2005 order, construction costs related to the project were recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

The level of depreciation expense and related tax benefit recognized in the income statement 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 may decline as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, they can have a significant impact on individual line items within the income statement. In addition, SCE&G is allowed to record non-cash carrying costs on the unrecovered investment, which is described further at Other Income. See also Regulatory Matters - Synthetic Fuel. The accelerated depreciation, synthetic fuel tax credits, partnership losses and the income tax benefit arising from such losses recognized by SCE&G during the three and six months ended June 30, 2006 and 2005 are as follows:

	Second Quarter						Year to Date
Millions of dollars	2006			2005			2006			2005
Depreciation and amortization expense	$	(1.2	)	$	(13.9	)	$	(1.4	)	$	(183.6	)
Income tax benefits:
From synthetic fuel tax credits		3.3			11.2			6.6			155.2
From accelerated depreciation		0.5			5.3			0.6			70.2
From partnership losses		1.5			1.6			3.5			25.9
Total income tax benefits		5.3			18.1			10.7			251.3
Losses from Equity Method Investments		(4.1	)		(4.2	)		(9.3	)		(67.7	)
Impact on Net Income	$	-		$	-		$	-		$	-

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

Pension Income

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

	Second Quarter				Year to Date
Millions of dollars	2006		2005		2006		2005
Income Statement Impact:
Reduction in employee benefit costs	$	0.6	$	1.5	$	1.2	$	3.0
Other income		3.1		3.1		6.3		6.1
Balance Sheet Impact:
Reduction in capital expenditures		0.2		0.4		0.4		0.8
Component of amount due to Summer Station co-owner		0.1		0.1		0.1		0.3
Total Pension Income	$	4.0	$	5.1	$	8.0	$	10.2

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. Pension income for the second quarter and year to date 2006 decreased compared to the corresponding periods in 2005, primarily as a result of investment returns.

Other Income

Included in other income is an allowance for funds used during construction (AFC). AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income.

Also included in other income for the three and six months ended June 30, 2006 is a recovery of carrying costs through synthetic fuel tax credits of $2.0 million and $4.0 million, respectively, which was recorded under provisions of the January 2005 SCPSC rate order. The amounts for the corresponding periods ended June 30, 2005, were $3.0 million and $6.0 million, respectively.

Dividends Declared

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

Declaration Date	Amount	Quarter Ended	Payment Date
February 16, 2006	$39.2 million	March 31, 2006	April 1, 2006
April 27, 2006	$39.2 million	June 30, 2006	July 1, 2006
August 3, 2006	$39.2 million	September 30, 2006	October 1, 2006

Electric Operations

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

	Second Quarter							Year to Date
Millions of dollars	2006		% Change			2005		2006		% Change			2005
Operating revenues	$	464.3		5.6	%	$	439.8	$	863.9		0.7	%	$	857.5
Less: Fuel used in generation		146.6		6.9	%		137.2		264.1		(0.3	)%		265.0
Purchased power		8.2		(34.4	)%		12.5		11.9		(42.2	)%		20.6
Margin	$	309.5		6.7	%	$	290.1	$	587.9		2.8	%	$	571.9

Second Quarter

Margin increased by $9.6 million due to favorable weather, by $6.8 million due to customer growth and by $2.8 million due to off-system sales.

Year to Date

Margin increased by $12.7 million due to customer growth and by $5.2 million in increased off-system sales, offset primarily by $2.4 million due to unfavorable weather in the first quarter.

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	2006		% Change			2005		2006		% Change			2005
Operating revenues	$	88.8		4.7	%	$	84.8	$	281.5		16.5	%	$	241.7
Less: Gas purchased for resale		71.6		0.8	%		71.0		225.1		17.4	%		191.7
Margin	$	17.2		24.6	%	$	13.8	$	56.4		12.8	%	$	50.0

Second Quarter

Margin increased by $1.2 million due to increased retail base rates which became effective with the first billing cycle in November 2005, by $1.6 million due to higher firm margin and by $0.8 million due to other revenue.

Year to Date

Margin increased by $8.2 million due to increased retail base rates which became effective with the first billing cycle in November 2005 and by $0.4 million due to higher firm margin. These increases were offset by $2.6 million due to winter assistance credits.

Other Operating Expenses

Other operating expenses were as follows:

	Second Quarter							Year to Date
Millions of dollars	2006		% Change			2005		2006		% Change			2005
Other operation and maintenance	$	113.8		1.2	%	$	112.5	$	228.6		3.5	%	$	220.9
Depreciation and amortization		65.6		(15.6	)%		77.7		130.1		(58.2	)%		311.2
Other taxes		34.0		(5.6	)%		36.0		69.0		(2.7	)%		70.9
Total	$	213.4		(5.7	)%	$	226.2	$	427.7		(29.1	)%	$	603.0

Second Quarter

Other operation and maintenance expenses increased due to increased electric generation, transmission and distribution expenses and reduced pension income, partially offset by lower labor costs due to lower labor incentive compensation accruals. Depreciation and amortization decreased $12.5 million due to accelerated depreciation of the back-up dam at Lake Murray in 2005 (previously explained at Recognition of Synthetic Fuel Tax Credits) and the lower levels of credits recognized in 2006 due to applicability of the phase-down provisions as discussed above.

Year to Date

Other operation and maintenance expenses increased by $5.9 million primarily due to increased electric generation, transmission and distribution expenses and due to reduced pension income, partially offset by lower labor costs due to lower labor incentive compensation accruals. Depreciation and amortization decreased $182.2 million due to accelerated depreciation of the back-up dam at Lake Murray in 2005 (previously explained at Recognition of Synthetic Fuel Tax Credits) and the lower levels of credits recognized in 2006 due to applicability of the phase-down provisions as discussed above.

Income Taxes

Income tax expense for the six months ended June 30, 2006 increased primarily due to the initial application and recognition of synthetic fuel tax credits in the first quarter of 2005 and the phase down in 2006, as previously discussed at Recognition of Synthetic Fuel Tax Credits. In addition, other tax credits of $2.0 million were recorded in the first quarter of 2005.

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, 2006 was 3.33.

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, to expand to meet future demand for electricity and gas and to install equipment necessary to comply with environmental regulations 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.

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

SCE&G expects to require the addition of base load electrical generation by 2015 and is evaluating alternatives, including fossil- and nuclear-fueled generation. On February 10, 2006, SCE&G and Santee Cooper, a state-owned utility in South Carolina (joint owners of Summer Station) announced their selection of the Summer Station site as the preferred site for new nuclear generation should such generation be considered the best alternative in the future. Due to the significant lead time required for construction of nuclear generation, the joint owners are preparing an application to the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL) that would cover two new nuclear units. The COL application, which is expected to be completed and filed in 2007, would be reviewed by the NRC for an estimated three years. Issuance of a COL would not obligate the joint owners to build nuclear generation. The final decision to build nuclear generation will be influenced by several factors, including NRC licensing attainment, construction and operating costs, the cost of competing fuels, regulatory and environmental requirements and financial market conditions.

The following table summarizes how SCE&G generated and used funds for property additions and construction expenditures during the six months ended June 30, 2006 and 2005:

	Six Months Ended
	June 30,
Millions of dollars	2006			2005
Net cash provided from operating activities	$	237		$	72
Net cash provided from (used for) financing activities		(45	)		115
Cash provided from sale of assets		-			1
Cash and cash equivalents available at the beginning of the period		19			20
Funds used for utility property additions and construction expenditures		(181	)		(182	)
Funds used for investments		(17	)		(9	)

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 the SCPSC, the Securities and Exchange Commission and Federal Energy Regulatory Commission (FERC).

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

In June 2006 SCE&G issued $125 million of first mortgage bonds having an annual interest rate of 6.25% and maturing July 1, 2036. The proceeds from the sale of these bonds, together with available cash, were used for the payment at maturity of $131 million of SCE&G’s first and refunding mortgage bonds due July 15, 2006, which bore interest at 9.0%.

ENVIRONMENTAL MATTERS

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

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

The level of depreciation expense and related income tax benefit recognized in the income statement is equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of taxes. As a result, the balance of unrecovered costs in the dam remediation account may decline 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 back-up dam remediation account will be matched to available synthetic fuel tax credits on a quarterly basis until the balance in the dam remediation account is zero or until all of the available synthetic fuel tax credits have been utilized. Under current law, the synthetic fuel tax credit program expires at the end of 2007.

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

The benchmark price range for 2005, published in April 2006, is $53 to $67 per barrel, and no phase-out applied. However, SCE&G’s analysis indicates that the available synthetic fuel tax credits for 2006 are likely to be impacted by the phase-out calculation. As such, through June 2006 the Company recorded synthetic fuel tax credits and applied those credits to allow the recording of accelerated depreciation related to the balance in the dam remediation project account based on an estimate that only 38 percent of credits generated will be available (phase-out of 62 percent). The Company cannot predict what impact, if any, the price of oil may have on the Company’s ability to earn and utilize synthetic fuel tax credits in the future. However, there is significant uncertainty as to the continued availability of the credits in 2006 and 2007. The availability of these synthetic fuel tax credits is also subject to coal availability and other operational risks related to the generating plants.

If it is determined that available credits are not sufficient to fully recover the construction costs of the dam remediation, regulatory action to allow recovery of those remaining costs may be sought. As of June 30, 2006, remaining unrecovered costs, based on management’s recording of accelerated depreciation and related tax benefits, were $92.3 million.

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, 2006
Millions of dollars				Expected Maturity Date
							There-		Fair
Liabilities	2006	2007	2008		2009	2010	after	Total	Value
Long-Term Debt:
Fixed Rate ($)	134.5	39.2	39.2		139.2	45.8	1,832.7	2,230.6	2,176.3
Average Interest Rate (%)	8.97	6.86	6.86		6.33	6.66	5.91	6.17	n/a

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

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 dekatherms. Fair value represents quoted market prices.

Expected Maturity:
				Options
	Futures Contracts			Purchased Call	Sold Put
2006	Long	Short		(Long)	(Long)
Settlement Price (a)	8.63	7.44	Strike Price (a)	8.52	7.55
Contract Amount (b)	7.3	0.5	Contract Amount (b)	5.4	0.3
Fair Value (b)	7.3	0.4	Fair Value (b)	0.8	-
2007
Settlement Price (a)	9.76	10.37	Strike Price (a)	-	-
Contract Amount (b)	14.3	1.5	Contract Amount (b)	-	-
Fair Value (b)	14.8	1.6	Fair Value (b)	-	-
(a) Weighted average, in dollars
(b) Millions of dollars

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

FINANCIAL SECTION

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

ITEM 1. FINANCIAL STATEMENTS

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,			December 31,
Millions of dollars	2006			2005
Assets
Gas Utility Plant	$	1,047		$	1,006
Accumulated Depreciation		(234	)		(282	)
Acquisition Adjustment		210			210
Gas Utility Plant, Net		1,023			934
Nonutility Property and Investments, Net		28			28
Current Assets:
Cash and cash equivalents		3			3
Restricted cash and temporary investments		-			1
Receivables, net of allowance for uncollectible accounts of $2 and $3		43			182
Receivables-affiliated companies		2			9
Inventories (at average cost):
Stored gas		80			92
Materials and supplies		6			6
Deferred income taxes, net		1			-
Other		1			3
Total Current Assets		136			296
Deferred Debits and Other Assets:
Due from affiliate-pension asset		10			11
Regulatory assets		42			26
Other		3			3
Total Deferred Debits and Other Assets		55			40
Total	$	1,242		$	1,298

	June 30,		December 31,
Millions of dollars	2006		2005
Capitalization and Liabilities
Capitalization:
Common equity	$	542	$	528
Long-term debt, net		266		270
Total Capitalization		808		798
Current Liabilities:
Short-term borrowings		34		99
Current portion of long-term debt		3		3
Accounts payable		32		91
Accounts payable-affiliated companies		4		6
Customer deposits and customer prepayments		13		14
Taxes accrued		1		4
Interest accrued		6		6
Distributions/dividends declared		4		4
Deferred income taxes, net		-		3
Other		8		6
Total Current Liabilities		105		236
Deferred Credits and Other Liabilities:
Deferred income taxes, net		106		104
Deferred investment tax credits		1		1
Due to affiliate-postretirement benefits		20		19
Other regulatory liabilities		23		23
Asset retirement obligations		13		13
Other asset removal costs		155		91
Other		11		13
Total Deferred Credits and Other Liabilities		329		264
Commitments and Contingencies (Note 4)		-		-
Total	$	1,242	$	1,298

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

		Three Months Ended						Six Months Ended
		June 30,						June 30,
Millions of dollars		2006			2005			2006			2005
Operating Revenues		$	77		$	84		$	330		$	329
Cost of Gas			49			53			232			225
Gross Margin			28			31			98			104
Operating Expenses:
Operation and maintenance			19			19			39			40
Depreciation and amortization			9			9			18			17
Other taxes			2			2			4			4
Total Operating Expenses			30			30			61			61
	��
Operating Income (Loss)			(2	)		1			37			43
Other Income (Expense):
Other income			2			2			6			6
Other expenses			(2	)		(2	)		(4	)		(4	)
Interest charges, net of allowance for borrowed funds
used during construction			(6	)		(5	)		(11	)		(11	)
Total Other Expense			(6	)		(5	)		(9	)		(9	)
Income (Loss) Before Income Taxes, Earnings from Equity Method
Investments and Cumulative Effect of Accounting Change			(8	)		(4	)		28			34
Income Tax Expense (Benefit)			(3	)		(1	)		12			14
Income (Loss) Before Earnings from Equity Method Investments
and Cumulative Effect of Accounting Change			(5	)		(3	)		16			20
Earnings from Equity Method Investments			1			1			2			2
Cumulative Effect of Accounting Change, net of taxes			-			-			1			-
Net Income (Loss)		$	(4	)	$	(2	)	$	19		$	22

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

	Six Months Ended
	June 30,
Millions of dollars	2006			2005
Cash Flows From Operating Activities:
Net income	$	19		$	22
Adjustments to reconcile net income to net cash provided from operating activities:
Cumulative effect of accounting change, net of taxes		(1	)		-
Depreciation and amortization		19			18
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		146			88
Inventories		12			15
Regulatory assets		(1	)		(3	)
Regulatory liabilities		1			1
Accounts payable		(68	)		(41	)
Deferred income taxes, net		(2	)		-
Taxes accrued		(3	)		(2	)
Changes in gas adjustment clauses		(16	)		19
Changes in other assets		3			2
Changes in other liabilities		1			(8	)
Net Cash Provided From Operating Activities		110			111
Cash Flows From Investing Activities:
Construction expenditures, net of AFC		(36	)		(24	)
Nonutility and other		(1	)		6
Net Cash Used For Investing Activities		(37	)		(18	)
Cash Flows From Financing Activities:
Short-term borrowings, net		(65	)		(58	)
Contributions from parent		3			2
Retirement of long-term debt		(3	)		(3	)
Distributions/dividends		(8	)		(7	)
Net Cash Used For Financing Activities		(73	)		(66	)
Net Increase In Cash and Cash Equivalents		-			27
Cash and Cash Equivalents, January 1		3			1
Cash and Cash Equivalents, June 30	$	3		$	28
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $0.3 and $0.2)	$	10		$	9
- Income taxes		18			17
Noncash Investing and Financing Activities:
Accrued construction expenditures		4			1

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2006

(Unaudited)

The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in Public Service Company of North Carolina, Incorporated’s (PSNC Energy, and together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, 2005. These are interim financial statements, and due to the seasonality of the Company’s business and matters that may occur during the rest of the year, the amounts reported in the Condensed Consolidated Statements of Operations are not necessarily indicative of amounts expected for the full year. In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature, which are necessary for a fair statement of the results for the interim periods reported.

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.      Basis of Accounting

The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71,“Accounting 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, 2006 the Company has recorded the regulatory assets and regulatory liabilities summarized as follows.

	June 30,		December 31,
Millions of dollars	2006		2005
Regulatory Assets:
Under-collections - gas cost adjustment clause	$	20	$	5
Environmental remediation costs		10		10
Asset retirement obligations		10		10
Other		2		1
Total Regulatory Assets	$	42	$	26

Regulatory Liabilities:
Over-collections - gas cost adjustment clause	$	20	$	20
Other asset removal costs		155		91
Other		3		3
Total Regulatory Liabilities	$	178	$	114

Under- and over-collections-gas cost adjustment clauses represent amounts under- or over-collected from customers pursuant to the Company’s Rider D mechanism approved by the North Carolina Utilities Commission (NCUC). This mechanism allows the Company to recover all prudently incurred gas costs.

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 by the Company at such sites has been recovered through rates. Amounts incurred and deferred, net of insurance settlements, that are not currently being recovered through rates are $3.6 million. Management believes that these costs and the estimated remaining costs of $6.6 million will be recoverable through rates.

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

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

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

B.      Total Comprehensive Income

Total comprehensive income was not significantly different from net income for any period reported. Accumulated other comprehensive income (loss) of the Company totaled $(0.1) million and $(0.3) million as of June 30, 2006 and December 31, 2005, respectively.

C.      Transactions with Affiliates

The Company has related party transactions with its equity method investees. The Company records as cost of gas the storage and transportation costs charged by these investees. These costs totaled $7.8 million for the six months ended June 30, 2006 and 2005. The Company owed these investees $1.3 million at June 30, 2006 and December 31, 2005. The Company received cash distributions from equity investees of $2.3 million and $2.5 million for the six months ended June 30, 2006 and 2005, respectively.

During the six months ended June 30, 2006 and 2005, the Company made sales to an affiliate of natural gas and transportation services of $5.7 million and $10.7 million, respectively.

At June 30, 2006, the Company owed an affiliate $0.1 million related to billing and collection services for energy-related products and service contracts.

D.    New Accounting Matters

The Company adopted SFAS 154, “Accounting Changes and Error Corrections,” in the first quarter of 2006. SFAS 154 requires retrospective application to financial statements of prior periods for every voluntary change in accounting principle unless such retrospective application is impracticable. SFAS 154 replaces Accounting Principles Board (APB) Opinion 20, “Accounting Changes,” and SFAS 3, “Reporting Accounting Changes in Interim Financial Statements,” although it carries forward some of their provisions. The adoption of SFAS 154 had no material impact on the Company’s results of operations, cash flows or financial position.

SFAS 123 (revised 2004),“Share-Based Payment” (SFAS 123(R)), requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) replaces SFAS 123, “Accounting for Stock-Based Compensation” and supersedes APB 25, “Accounting for Stock Issued to Employees.” The cumulative effect of the adoption of SFAS 123(R) on January 1, 2006 resulted in a $0.7 million (net of tax) gain in the first quarter of 2006 based on a reduction of prior compensation accruals for performance awards granted in 2004 and 2005.

FIN 48, “Accounting for Uncertainty in Income Taxes,” was issued in June 2006. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company will adopt FIN 48 in the first quarter of 2007. The Company is continuing to evaluate the impact that adoption of FIN 48 may have on the Company’s results of operations, cash flows or financial position.

E.    Reclassifications

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

2.         RATE AND OTHER REGULATORY MATTERS

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

The Company’s benchmark cost of gas in effect during the period January 1, 2005 through June 30, 2006 was as follows:

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

On June 1, 2006, the Company filed testimony in the 2006 Annual Prudence Review related to the 12 months ended March 31, 2006. The NCUC will hold a hearing in August 2006 to consider the filing.

On April 3, 2006, the Company filed an application with the NCUC requesting a 4.9 percent, or $28.4 million, increase in its base rates. In that application the Company also requested a $7.5 million reduction in the fixed-cost portion of its cost of gas which, if approved would result in an overall increase of 3.6 percent, or $20.9 million, in rates and charges for natural gas utility service. The rate increase is largely associated with recovering increased plant investment and operating costs. If approved, the new rates will be effective for the 2006-2007 winter season. A hearing is scheduled for August 2006.

On January 11, 2006, the NCUC approved the Company’s request to place all impacts to its results of operation caused by the adoption of FIN 47 in regulatory deferred accounts. SFAS 143, together with FIN 47, provides guidance for recording and disclosing liabilities related to future legally enforceable obligations to retire assets (ARO).

On March 14, 2006, the NCUC authorized the Company to place pipeline supplier refunds that it presently holds and future supplier refunds into the appropriate deferred accounts for the over- or under-recovery of gas costs. Prior to this authorization, refunds from the Company’s interstate pipeline transporters were placed in a state-approved expansion fund to provide financing for expansion into areas that otherwise would not be economically feasible to serve. In September 2005, the NCUC approved the Company’s request for disbursement of up to $1.1 million from the state expansion fund to extend natural gas service to Louisburg, North Carolina. The project will be completed in 2006.

3.     FINANCIAL INSTRUMENTS

 The Company utilizes swap agreements to manage interest rate risk. These transactions are more fully described in Note 7 to the consolidated financial statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005.

The Company also utilizes derivative financial instruments for hedging natural gas purchases. The Company’s tariffs include a provision for the recovery of actual gas costs incurred. Transaction fees and any realized gains or losses are recorded in deferred accounts as a regulatory asset or liability for the over- or under-recovery of gas costs for subsequent rate consideration. As of June 30, 2006, the Company had a deferred net realized gain of $6.5 million. In addition, as of June 30, 2006, the Company had unrealized losses of $5.8 million, also recorded in other regulatory assets.

The Company also utilizes a swap agreement to manage interest rate risk. At June 30, 2006 the estimated fair value of the Company’s swap was $0.1 million (loss) related to a notional amount of $19.2 million.

The Company utilizes asset management and supply service agreements with counterparties for certain of its natural gas storage facilities.  At June 30, 2006, such counterparties held 45% of the Company’s total natural gas inventory, with a value of $33.7 million.  This natural gas will be returned to the Company at its city gate during the winter period (November 2006 through March 2007), or on the contract settlement date, as applicable.  Under the terms of the asset management agreements, the Company receives storage asset management fees and, in certain instances, a share of excess profits.  No fees are received under supply service agreements.  The agreements expire at various times from October 31, 2006 through March 31, 2007.

4.         COMMITMENTS AND CONTINGENCIES

The Company is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. The Company’s 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 $6.6 million, which reflects its estimated remaining liability at June 30, 2006. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through rates are $3.6 million. Any cost arising from the remediation of these sites is expected to be recoverable through rates.

5.       SEGMENT OF BUSINESS INFORMATION

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

			2006									2005
			Operating			Net								Net
Millions of dollars	External Revenue		Income (Loss)			Income (Loss)			Segment Assets	External Revenue		Operating Income		Income (Loss)			Segment Assets
Three Months Ended June 30,
Gas Distribution	$	77	$	(2	)	$	(4	)		$	84	$	1	$	(2	)
All Other		-		n/a			-				-		n/a		-
Adjustments/Eliminations		-		-			-				-		-		-
Consolidated Total	$	77	$	(2	)	$	(4	)		$	84	$	1	$	(2	)

Six Months Ended June 30,
Gas Distribution	$	330	$	37	$	19	$	1,078	$	329	$	43	$	22	$	1,007
All Other		-		n/a		-		28		-		n/a		-		28
Adjustments/Eliminations		-		-		-		136		-		-		-		70
Consolidated Total	$	330	$	37	$	19	$	1,242	$	329	$	43	$	22	$	1,105

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

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

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, 2005.

Statements included in this narrative analysis (or elsewhere in this quarterly report) which are not statements of historical fact are intended to be, and are hereby identified as, “forward-looking statements” for purposes of the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following: (1) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) regulatory actions or changes in the utility regulatory environment, (3) current and future litigation, (4) changes in the economy, especially in PSNC Energy’s service territory, (5) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (6) growth opportunities, (7) the results of financing efforts, (8) changes in accounting principles, (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, 2006 decreased $3.5 million compared to the same period in 2005, primarily due to decreased 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 2006:

Declaration Date	Amount	Quarter Ended	Payment Date
February 16, 2006	$3.9 million	March 31, 2006	April 1, 2006
April 27, 2006	$3.9 million	June 30, 2006	July 1, 2006
August 3, 2006	$3.9 million	September 30, 2006	October 1, 2006

Gas Distribution

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

	Six Months Ended June 30,
Millions of dollars	2006		% Change			2005
Operating revenues	$	329.7		0	%	$	329.7
Less: Gas purchased for resale		231.6		2.8	%		225.3
Margin	$	98.1		(6.0	)%	$	104.4

Gas distribution sales margin decreased primarily due to lower customer usage, despite a 4 percent increase in customer growth. This decrease in consumption is attributable to conservation due to higher natural gas prices and due to milder weather.

Income Taxes

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

Capital Expansion Program and Liquidity Matters

PSNC Energy’s capital expansion program includes the construction of lines, systems and facilities and the purchase of related equipment. PSNC Energy’s 2006 construction budget is $71 million, compared to actual construction expenditures through June 30, 2006 of $43.3 million. PSNC Energy’s ratio of earnings to fixed charges for the 12 months ended June 30, 2006 was 2.67.

ITEM 4. CONTROLS AND PROCEDURES

As of June 30, 2006 each of SCANA Corporation (SCANA), South Carolina Electric & Gas Company (SCE&G) and Public Service Company of North Carolina, Incorporated (PSNC Energy) conducted separate evaluations under the supervision and with the participation of its management, including its Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of its disclosure controls and procedures. Based on these evaluations, the CEO and CFO in each case concluded that as of June 30, 2006 disclosure controls and procedures related to each company were effective. There has been no change in SCANA’s, SCE&G’s or PSNC Energy’s internal control over financial reporting during the quarter ended June 30, 2006 that has materially affected or is reasonably likely to materially affect SCANA’s, SCE&G’s or PSNC Energy’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Each of SCANA Corporation (SCANA), South Carolina Electric & Gas Company (SCE&G) and Public Service Company of North Carolina, Incorporated (PSNC Energy) are engaged in various claims and litigation incidental to their business operations which management anticipates will be resolved without material loss. The status of matters previously disclosed in their respective 2005 Annual Reports on Form 10-K have not changed significantly, except as follows.

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.  In accordance with generally accepted accounting principles, in the third quarter of 2004 SCANA accrued a liability of $18 million, which was its reasonable estimate of the minimum liability that was probable if the final judgment were to be consistent with the jury verdict.  While the judgment was being appealed, in May 2006 SCANA paid the plaintiff $11 million in settlement of its claims.  The Court’s procedural process for disposing of the litigation is underway.

         SCANA is also defending a claim for $2.7 million for reimbursement of legal fees and expenses under an indemnification and hold harmless agreement in the contract for the sale of the propane gas assets. A bench trial on the indemnification was held in January 2005, and in August 2005 an order was entered against SCANA in the amount of $2.6 million.  In December 2005, the judge vacated this award, and further motions to review his order are pending. SCANA has made provision for this potential loss and further believes that the resolution of this claim will not have a material adverse impact on its results of operations, cash flows or financial condition.

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).

The Annual Meeting of Shareholders of SCANA Corporation Common Stock (No Par Value) was held on April 27, 2006. The following matters were voted upon at the meeting.

1. To elect four (4) Class I Directors and one (1) Class III Director for the terms specified in the Proxy Statement.

Nominee	Number of Shares Voting  For	Number of Shares Voting to Withhold Authority	Total Shares Voted
James A. Bennett	97,261,876	1,113,554	98,375,430
William C. Burkhardt	97,418,044	957,386	98,375,430
Lynne M. Miller	97,378,184	997,246	98,375,430
Maceo K. Sloan	97,234,717	1,140,713	98,375,430
Sharon A. Decker	97,294,934	1,080,496	98,375,430

2. To approve the appointment of Deloitte & Touche LLP as independent auditors for SCANA Corporation.

	Number of Shares
FOR	97,416,111
AGAINST	607,664
ABSTAIN	351,655
TOTAL	98,375,430

ITEM 6. EXHIBITS

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

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

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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. 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 7, 2006	James E. Swan, IV
	Controller
	(Principal accounting officer)

EXHIBIT INDEX

	Applicable to Form 10-Q of
Exhibit			PSNC
No.	SCANA	SCE&G	Energy	Description
3.12		X		Articles of Amendment dated March 14, 2006, amending the Restated Articles of Incorporation of South Carolina Electric & Gas Company (Filed as Exhibit 3.01 to Form 8-K filed March 17, 2006)
3.13		X		Articles of Correction dated March 17, 2006, amending the Articles of Amendment dated March 14, 2006 of South Carolina Electric & Gas Company (Filed as Exhibit 3.02 to Form 8-K filed March 17, 2006)
3.14		X		Articles of Amendment dated May 11, 2006, amending the Restated Articles of Incorporation of South Carolina Electric & Gas Company (Filed as Exhibit 3.01 to Form 8-K filed May 15, 2006)
3.15		X		Articles of Amendment dated June 28, 2006, amending the Restated Articles of Incorporation of South Carolina Electric & Gas Company (filed as Exhibit 3.01 to Form 8-K filed June 29, 2006)
*10.01	X			Amendment to SCANA Corporation Director Compensation and Deferral Plan as adopted December 20, 2005 (Filed as Exhibit 10.01 to Form 10-Q for the quarter ended March 31, 2006)
*10.02	X			Amendment to SCANA Corporation Executive Deferred Compensation Plan as adopted December 20, 2005 (Filed as Exhibit 10.02 to Form 10-Q for the quarter ended March 31, 2006)
*10.03	X			Independent contractor agreement with Neville O. Lorick (Filed as Exhibit 99.1 to Form 8-K dated June 15, 2006 and incorporated by reference herein)
31.01	X			Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.02	X			Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
31.03		X		Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.04		X		Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
31.05			X	Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.06			X	Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
32.01	X			Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.02	X			Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
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)

*Management contract or compensation plan or arrangement