Scana 10-Q 2007 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, 2007

OR

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

For the Transition Period from             to             

Commission	Registrant, State of Incorporation,	I.R.S. Employer
File Number	Address and Telephone Number	Identification No.
1-8809	SCANA Corporation	57-0784499
	(a South Carolina corporation)
	1426 Main Street, Columbia, South Carolina 29201
	(803) 217-9000
1-3375	South Carolina Electric & Gas Company	57-0248695
	(a South Carolina corporation)
	1426 Main Street, Columbia, South Carolina 29201
	(803) 217-9000

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 □

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

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 □No x 

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

	Description of	Shares Outstanding
Registrant	Common Stock	at July 31, 2007
SCANA Corporation	Without Par Value	116,664,933
South Carolina Electric & Gas Company	$4.50 Par Value	40,296,147 (a)
(a)Owned beneficially and of record by SCANA Corporation.

This combined Form 10-Q is separately filed by SCANA Corporation and South Carolina Electric & Gas Company. 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 company.

TABLE OF CONTENTS

JUNE 30, 2007

				Page
Cautionary Statement Regarding Forward-Looking Information
PART I. FINANCIAL INFORMATION
SCANA Corporation Financial Section				4
	Item 1.		Financial Statements	5
			Condensed Consolidated Balance Sheets	5
			Condensed Consolidated Statements of Income	7
			Condensed Consolidated Statements of Cash Flows	8
			Condensed Consolidated Statements of Comprehensive Income	9
			Notes to Condensed Consolidated Financial Statements	10
	Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
	Item 3.		Quantitative and Qualitative Disclosures About Market Risk	25
	Item 4.		Controls and Procedures	26
South Carolina Electric & Gas Company Financial Section				27
	Item 1.		Financial Statements	28
			Condensed Consolidated Balance Sheets	28
			Condensed Consolidated Statements of Income	30
			Condensed Consolidated Statements of Cash Flows	31
			Notes to Condensed Consolidated Financial Statements	32
	Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
	Item 3.		Quantitative and Qualitative Disclosures About Market Risk	44
	Item 4T.		Controls and Procedures	45
PART II. OTHER INFORMATION				46
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		46
Item 4.		Submission of Matters to a Vote of Security Holders		46
Item 6.		Exhibits		47
Signatures				48
Exhibit Index				49

Statements included in this Quarterly Report on Form 10-Q 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. Forward-looking statements include, but are not limited to, statements concerning key earnings drivers, customer growth, environmental regulations and expenditures, leverage ratio, projections for pension fund contributions, financing activities, access to sources of capital, impacts of the adoption of new accounting rules, estimated construction and other expenditures and factors affecting the availability of synthetic fuel tax credits. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential” or “continue” or the negative of these terms or other similar terminology. 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)       the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment;

(2)       regulatory actions, particularly changes in rate regulation and environmental regulations;

(3)       current and future litigation;

(4)       changes in the economy, especially in areas served by subsidiaries of SCANA Corporation (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 SCANA’s or its subsidiaries’ accounting rules and accounting policies;

(9)       weather conditions, especially in areas served by SCANA's subsidiaries;

(10)      payment by counterparties as and when due;

(11)      the availability of fuels such as coal, natural gas and enriched uranium used to produce electricity; the availability

            of purchased power and natural gas for distribution; the level and volatility of future market prices for such fuels

            and purchased power; and the ability to recover the costs for such fuels and purchased power;

(12)      performance of SCANA's pension plan assets;

(13)      inflation;

(14)      compliance with regulations; and

(15)      the other risks and uncertainties described from time to time in the periodic reports filed by SCANA or South

           Carolina Electric & Gas Company (SCE&G) with the United States Securities and Exchange Commission (SEC).

SCANA and SCE&G disclaim any obligation to update any forward-looking statements.

PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

SCANA CORPORATION

(Unaudited)

	June 30,			December 31,
Millions of dollars	2007			2006
Assets
Utility Plant In Service	$	9,494		$	9,227
Accumulated Depreciation and Amortization		(2,923	)		(2,815	)
		6,571			6,412
Construction Work in Progress		312			326
Nuclear Fuel, Net of Accumulated Amortization		66			39
Acquisition Adjustments		230			230
Utility Plant, Net		7,179			7,007
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $77 and $70		154			132
Assets held in trust, net-nuclear decommissioning		58			56
Other investments		88			88
Nonutility Property and Investments, Net		300			276
Current Assets:
Cash and cash equivalents		90			201
Receivables, net of allowance for uncollectible accounts of $16 and $14		500			655
Receivables - affiliated companies		29			32
Inventories (at average cost):
Fuel		261			300
Materials and supplies		99			93
Emission allowances		43			22
Prepayments and other		34			39
Deferred income taxes		26			34
Total Current Assets		1,082			1,376
Deferred Debits and Other Assets:
Pension asset, net		212			200
Emission allowances		-			27
Regulatory assets		770			792
Other		119			139
Total Deferred Debits and Other Assets		1,101			1,158
Total	$	9,662		$	9,817

	June 30,		December 31,
Millions of dollars	2007		2006
Capitalization and Liabilities
Shareholders’ Investment:
Common equity	$	2,894	$	2,846
Preferred stock (Not subject to purchase or sinking funds)		106		106
Total Shareholders’ Investment		3,000		2,952
Preferred Stock, net (Subject to purchase or sinking funds)		7		8
Long-Term Debt, net		2,959		3,067
Total Capitalization		5,966		6,027
Current Liabilities:
Short-term borrowings		509		487
Current portion of long-term debt		118		43
Accounts payable		281		414
Accounts payable - affiliated companies		27		27
Customer deposits and customer prepayments		77		85
Taxes accrued		89		121
Interest accrued		51		51
Dividends declared		54		51
Other		83		126
Total Current Liabilities		1,289		1,405
Deferred Credits and Other Liabilities:
Deferred income taxes, net		943		947
Deferred investment tax credits		104		120
Asset retirement obligations		300		292
Postretirement benefits		197		194
Regulatory liabilities		748		714
Other		115		118
Total Deferred Credits and Other Liabilities		2,407		2,385
Commitments and Contingencies (Note 5)		-		-
Total	$	9,662	$	9,817

See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Millions of dollars, except per share amounts		2007			2006			2007			2006
Operating Revenues:
Electric		$	470		$	461		$	913		$	859
Gas - regulated			191			215			627			730
Gas - nonregulated			346			268			830			744
Total Operating Revenues			1,007			944			2,370			2,333
Operating Expenses:
Fuel used in electric generation			153			147			309			264
Purchased power			7			8			18			12
Gas purchased for resale			447			403			1,174			1,213
Other operation and maintenance			160			150			334			307
Depreciation and amortization			86			77			177			153
Other taxes			38			37			79			76
Total Operating Expenses			891			822			2,091			2,025
Operating Income			116			122			279			308
Other Income (Expense):
Other income			18			23			47			81
Other expenses			(8	)		(7	)		(26	)		(53	)
Interest charges, net of allowance for borrowed funds
used during construction of  $3, $2, $5 and $3			(51	)		(53	)		(103	)		(107	)
Gain on sale of assets			-			-			1			-
Preferred dividends of subsidiary			(2	)		(2	)		(4	)		(4	)
Allowance for equity funds used during construction			1			-			1			-
Total Other Expense			(42	)		(39	)		(84	)		(83	)
Income Before Income Tax Expense, Losses from Equity
Method Investments and Cumulative Effect of Accounting Change			74			83			195			225
Income Tax Expense			17			23			48			69
Income Before Losses from Equity Method
Investments and Cumulative Effect of Accounting Change			57			60			147			156
Losses from Equity Method Investments			(2	)		(2	)		(7	)		(6	)
Cumulative Effect of Accounting Change, net of taxes			-			-			-			6
Net Income		$	55		$	58		$	140		$	156
Basic and Diluted Earnings Per Share of Common Stock:
Before Cumulative Effect of Accounting Change		$	.47		$	.50		$	1.20		$	1.30
Cumulative Effect of Accounting Change, net of taxes			-			-			-			.05
Basic and Diluted Earnings Per Share		$	.47		$	.50		$	1.20		$	1.35
Weighted Average Shares Outstanding (millions)			116.7			115.5			116.7			115.3
See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION

(Unaudited)

	Six Months Ended
	June 30,
Millions of dollars		2007			2006
Cash Flows From Operating Activities:
Net income		$	140		$	156
Adjustments to reconcile net income to net cash provided from operating activities:
Cumulative effect of accounting change, net of taxes			-			(6	)
Excess losses, net of distributions from equity method investments			10			6
Depreciation and amortization			182			154
Amortization of nuclear fuel			9			9
Hedging activities			3			(3	)
Carrying cost recovery			(1	)		(4	)
Gain on sale of assets			(1	)		-
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net			158			363
Inventories			10			5
Prepayments and other			8			(12	)
Pension asset			(12	)		(7	)
Other regulatory assets			22			10
Deferred income taxes, net			4			14
Regulatory liabilities			10			22
Postretirement benefits			3			4
Accounts payable			(112	)		(214	)
Taxes accrued			(32	)		(25	)
Changes in fuel adjustment clauses			(13	)		13
Changes in other assets			15			26
Changes in other liabilities			(49	)		(42	)
Net Cash Provided From Operating Activities			354			469
Cash Flows From Investing Activities:
Utility property additions and construction expenditures			(312	)		(224	)
Proceeds from sale of assets			1			18
Nonutility property additions			(31	)		(21	)
Investments			(10	)		(21	)
Net Cash Used For Investing Activities			(352	)		(248	)
Cash Flows From Financing Activities:
Proceeds from issuance of debt			-			123
Proceeds from issuance of common stock			-			40
Repurchase of equity securities			(4	)		-
Repayment of debt			(31	)		(11	)
Dividends			(100	)		(97	)
Short-term borrowings, net			22			(178	)
Net Cash Used For Financing Activities			(113	)		(123	)
Net Increase (Decrease) In Cash and Cash Equivalents			(111	)		98
Cash and Cash Equivalents, January 1			201			62
Cash and Cash Equivalents, June 30		$	90		$	160
Supplemental Cash Flow Information:
Cash paid for  - Interest (net of capitalized interest of $5 and $3)		$	104		$	107
- Income taxes			26			38
Noncash Investing and Financing Activities:
Accrued construction expenditures			34			18

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		2007			2006			2007		2006
Net Income		$	55		$	58		$	140	$	156
Other Comprehensive Income, net of tax:
Unrealized gains (losses) on hedging activities:
Unrealized holding gains (losses) arising during period			(6	)		(5	)		1		(20	)
Reclassification adjustment for losses included in net income			-			4			11		17
Total Comprehensive Income (1)		$	49		$	57		$	152	$	153
(1) Accumulated other comprehensive loss totaled $16.9 million as of June 30, 2007 and $29.2 million as of
December 31, 2006.
See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION

June 30, 2007

(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, 2006. 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	2007		2006
Regulatory Assets:
Accumulated deferred income taxes	$	174	$	174
Under-collections - electric fuel and gas cost adjustment clauses		81		95
Deferred purchased power costs		4		9
Environmental remediation costs		28		29
Asset retirement obligations and related funding		271		264
Franchise agreements		52		55
Deferred regional transmission organization costs		7		8
Deferred employee benefit plan costs		138		142
Other		15		16
Total Regulatory Assets	$	770	$	792

Regulatory Liabilities:
Accumulated deferred income taxes	$	36	$	38
Over-collections - electric fuel and gas cost adjustment clauses		15		8
Other asset removal costs		621		599
Storm damage reserve		47		44
Planned major maintenance		9		6
Other		20		19
Total Regulatory Liabilities	$	748	$	714

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. Included in these amounts are regulatory assets or liabilities arising from realized and unrealized gains and losses incurred in the natural gas hedging programs of the Company’s regulated operations.

Deferred purchased power costs represent costs necessitated by outages at two of South Carolina Electric & Gas Company’s (SCE&G) 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 $17.2 million remain to be recovered. SCE&G is authorized to amortize $1.4 million of these costs on an annual basis.  Costs incurred through June 30, 2006, at sites owned by Public Service Company of North Carolina, Incorporated (PSNC Energy) are being recovered through rates over a three-year period. In addition, management believes that costs incurred subsequent to June 30, 2006, totaling $2.3 million at June 30, 2007, and the estimated remaining costs to be incurred of $5.4 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 electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years.

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

Deferred employee benefit plan costs represent pension and other postretirement benefit costs which were accrued as liabilities under provision of SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” but which are expected to be recovered through utility rates.

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

The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $50 million, which 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, 2007, no amounts were drawn from this reserve.

Planned major maintenance related to certain fossil hydro turbine/generation 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, beginning in January 2005, through electric rates to offset turbine maintenance expenditures. Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.

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

 In accordance with SFAS 128, “Earnings Per Share,” the Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. The Company computes diluted earnings per share using this same formula, 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 issued no securities that would have an antidilutive effect on earnings per share.

C.       Affiliated Transactions

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 $28.4 million at June 30, 2007 and $31.8 million at December 31, 2006.  SCE&G’s payables to these affiliated companies were $26.6 million at June 30, 2007 and $26.6 million at December 31, 2006.

SCE&G purchases shaft horsepower from a cogeneration facility.  The facility is owned by a limited liability company (LLC) in which SCANA holds an equity-method investment.  SCE&G’s payables to the LLC were $2.4 million at June 30, 2007 and $2.5 million at December 31, 2006.  SCE&G purchased $6.1 million and $13.4 million of shaft horsepower from the LLC for the three and six months ended June 30, 2007, respectively, and purchased $6.4 million and $12.7 million of shaft horsepower from the LLC for the three and six months ended June 30, 2006, respectively.

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
Three months ended June 30,	2007			2006			2007		2006
Millions of dollars
Service cost	$	3.5		$	3.5		$	1.2	$	1.2
Interest cost		10.4			9.9			3.0		2.8
Expected return on assets		(20.1	)		(18.8	)		-		-
Prior service cost amortization		1.7			1.7			0.3		0.2
Transition obligation amortization		-			0.1			0.2		0.2
Amortization of actuarial loss		-			0.2			0.3		0.4
Net periodic benefit (income) cost	$	(4.5	)	$	(3.4	)	$	5.0	$	4.8

	Pension Benefits						Other Postretirement Benefits
Six months ended June 30,	2007			2006			2007		2006
Millions of dollars
Service cost	$	7.0		$	7.0		$	2.4	$	2.4
Interest cost		20.7			19.8			6.0		5.6
Expected return on assets		(40.2	)		(37.6	)		-		-
Prior service cost amortization		3.4			3.4			0.6		0.4
Transition obligation amortization		-			0.2			0.4		0.4
Amortization of actuarial loss		-			0.4			0.6		0.7
Net periodic benefit (income) cost	$	(9.1	)	$	(6.8	)	$	10.0	$	9.5

E.      New Accounting Matters

SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” was issued in February 2007. SFAS 159 allows entities to measure at fair value many financial instruments and certain other assets and liabilities that are not otherwise required to be measured at fair value. SFAS 159 is effective for fiscal years beginning after November 15, 2007. The Company has not determined what impact, if any, that adoption will have on the Company’s results of operations, cash flows or financial position.

SFAS 157, “Fair Value Measurements,” was issued in September 2006.  SFAS 157 establishes a framework for measuring fair value to increase the consistency and comparability in fair value measurements.  The Company will adopt SFAS 157 in the first quarter of 2008, and has not determined what impact, if any, the adoption will have on the Company’s results of operations, cash flows or financial position.

FIN 48, “Accounting for Uncertainty in Income Taxes,” 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 financial statement recognition threshold and measurement attributes for tax positions taken or expected to be taken in  tax returns. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.  The Company adopted FIN 48 in the first quarter of 2007.  The impact on the Company’s results of operations, cash flows or financial position is discussed at Note 1F.

FASB Staff Position (FSP) AUG AIR-1 “Accounting for Planned Major Maintenance Activities,” amended APB 28, “Interim Financial Reporting,” to prohibit the use of the accrue-in-advance method of accounting for planned major maintenance.  As disclosed in Note 1A, SCE&G has received specific SCPSC orders providing for use of accrue-in-advance accounting for certain planned major maintenance activities. Accordingly, SCE&G will continue to follow accrue-in-advance accounting as allowed under SFAS 71 for these activities. The Company’s adoption of FSP AUG AIR-1 in the first quarter of 2007 had no impact on the Company’s results of operations, cash flows or financial position.

F.      Income Taxes

The Company files a consolidated federal income tax return and the Company and its subsidiaries file various applicable state and local income tax returns.  The Internal Revenue Service (IRS) has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2001 are closed for additional assessment.  On July 30, 2007, the statute of limitations for the 2002 federal return expired, but no material changes resulted.  With a few exceptions, the Company is no longer subject to state and local income tax examinations by tax authorities for years before 2003.  The IRS has completed the examination of S. C. Coaltech No. 1 LP., a synthetic fuel partnership in which the Company has an interest, for the 2004 tax year.  The Company does not anticipate that any adjustments from the examination will have a material impact on the earnings, cash flows or the financial position of the Company.  The Company continues to believe that all of its synthetic fuel tax credits have been properly claimed.

In connection with the initial adoption of FIN 48 effective January 1, 2007, the Company removed $15 million of previously recognized tax benefits from its balance sheet.  Because regulatory liabilities had been recorded for these previously recognized tax benefits under the provisions of SFAS 71, these benefits had never been recognized in the Company’s earnings or retained earnings.  As a result, the initial adoption of FIN 48 had no effect on the Company’s equity.  The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $15 million.  Because the benefits would be amortized into earnings over a number of years under SFAS 71, the impact on any individual year’s effective tax rate would be immaterial.  No material changes in the status of our tax positions have occurred subsequent to adoption.

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  Through June 30, 2007, the Company has not accrued any significant amount of interest or tax penalties.

2.       RATE AND OTHER REGULATORY MATTERS

SCE&G

Electric

On June 15, 2007 SCE&G filed an application with the SCPSC requesting a 6.75% increase in retail electric rates.  The application, among other things, seeks recovery of costs incurred to perform mandatory environmental upgrades to SCE&G’s generating plants.  SCE&G’s application is expected to be heard by the SCPSC in November 2007.  If approved, the new rates would be effective in January 2008.

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

Gas

On June 15, 2007 SCE&G filed an application with the SCPSC requesting an increase in retail natural gas rates of 1.3%  under the terms of the Natural Gas Rate Stabilization Act (Stabilization Act).  The Stabilization Act is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas service infrastructure.  The SCPSC is expected to review SCE&G’s filing in October 2007.  If approved, the rate adjustment would be implemented with the first billing cycle in November 2007.

In September 2006, the SCPSC approved an increase in retail natural gas rates of 3.2% under the terms of the Stabilization Act.  The rate adjustment was 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 in October 2006 which authorized SCE&G to adjust its cost of gas on a monthly, rather than an annual, basis beginning in December 2006.   The cost of gas adjustment is based on a twelve-month rolling average.

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 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.

In June 2007, PSNC Energy filed testimony in the 2007 Annual Prudence Review related to the 12 months ended March 31, 2007.  The NCUC will hold a hearing in August 2007 to consider the filing.

In May 2007 the NCUC approved PSNC Energy’s request to eliminate the use of its current dual residential customer rate structure and replace it with a single residential rate.   The NCUC also ordered that PSNC Energy establish a new residential rate structure by November 1, 2007.  Accordingly, in July 2007, PSNC Energy filed a petition requesting NCUC approval to implement a residential service rate which has a winter/summer differential of 6 cents per therm.  The higher winter rate would help recover costs associated with operating the system during high customer demand.  If approved, all residential customers will be charged this rate effective November 1, 2007.  These changes in the rate structure will have no impact on 2007 earnings.

In October 2006, the NCUC granted PSNC Energy an annual increase in retail natural gas margin revenues of approximately $15.2 million, or 2.6 percent, which was offset by a $9.2 million decrease in fixed-gas cost revenues, for an overall increase of $6.0 million, or 1.0 percent. The new rates are based on an allowed overall rate of return of 8.9 percent, and became effective for services rendered on or after November 1, 2006. In connection with the rate increase, the NCUC approved PSNC Energy’s recovery through rates, over a three-year period, of certain costs for environmental remediation and pipeline integrity management.

3.       LONG-TERM DEBT

On February 15, 2007 SCANA redeemed at maturity $25 million of its medium-term notes which bore interest at 6.9%.

Substantially all of SCE&G’s and South Carolina Generating Company, Inc.’s (GENCO) electric utility plant is pledged as collateral in connection with long-term debt.

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, 2006.

At June 30, 2007 the estimated fair value of PSNC Energy’s interest rate swaps totaled less than $0.1 million (gain) related to combined notional amounts of $16.0 million.

The Company’s regulated gas operations (SCE&G and PSNC Energy) hedge natural gas purchasing activities using over-the-counter options and swaps and New York Mercantile Exchange (NYMEX) futures and options. SCE&G’s tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of 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 also include a provision for the recovery of actual gas costs incurred. PSNC Energy records premiums, transaction fees, margin requirements and any realized and unrealized gains or losses from 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 effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit.  The Company estimates that most of the June 30, 2007 unrealized loss balance of $5.9 million, net of taxes, will be reclassified from accumulated other comprehensive income (loss) to earnings within the next twelve months as an increase to gas cost if market prices remain at current levels. As of June 30, 2007, all of the Company's cash flow hedges settle by their terms before the end of 2010.

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain of its natural gas storage facilities.  At June 30, 2007, such counterparties held 45% of PSNC Energy’s natural gas inventory, with a carrying value of $30.7 million, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees and, in certain instances, a share of profits.  No fees are received under supply service agreements.  The agreements expire at various times through March 31, 2009.

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, 2006. Commitments and contingencies at June 30, 2007 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, the one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $14.1 million.

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

B.      Environmental

SCE&G

In March 2005, the United States 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, although compliance plans and cost to comply with the rule have not been determined. Such costs will be material and are expected to be recoverable through rates.

In March 2005, the EPA issued a final rule establishing a mercury emissions cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. 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 53 others, by the EPA as a potentially responsible party (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. The 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.  The EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The site has not been remediated nor has a clean-up 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, net of insurance recoveries, if any, is expected to be recoverable through rates.

SCE&G has been named, along with 29 others, by the EPA as a 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 approximately 1959 to 1986.  During that time, SCE&G occasionally used CTC for the repair of existing transformers, purchase of new transformers and sale of used transformers.  In 1984, the EPA initiated a remediation of PCB-contaminated soil and groundwater at the site.  The EPA reports that it has spent $36 million to date.  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, net of insurance recoveries, if any, is expected to be recoverable through rates.

SCE&G maintains an environmental assessment program to identify and evaluate its current and former MGP sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate 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 clean-up relate solely to regulated operations. SCE&G defers site assessment and clean-up costs and recovers them through rates (see Note 1). Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $17.2 million at June 30, 2007. 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 2007, with certain monitoring and retreatment activities continuing through 2012. As of June 30, 2007, SCE&G had spent $22.3 million to remediate the site and expects to spend an additional $1.0 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. SCE&G expects to recover any cost arising from the remediation of this site 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 2011. As of June 30, 2007, SCE&G has spent $4.8 million related to these three sites, and expects to spend an additional $11.2 million. SCE&G expects to recover any cost arising from the remediation of these sites through rates.

PSNC Energy

PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy's actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. PSNC Energy has recorded a liability and associated regulatory asset of $5.4 million, which reflects its estimated remaining liability at June 30, 2007. PSNC Energy expects to recover any cost allocable to PSNC Energy arising from the remediation of these sites 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 South Carolina Electric & Gas Company in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit.  The plaintiffs subsequently dismissed defendants Duke Energy and Progress Energy and proceeded against SCE&G only. The plaintiffs sought damages for the alleged improper use of electric transmission and distribution easements but did not assert a dollar amount for their claims. Specifically, the plaintiffs alledged 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 utility’s internal use along the electric transmission and distribution line rights-of-way constituted a trespass. On July 20, 2007, Plaintiffs’ counsel filed a Stipulation of Dismissal Without Prejudice with the Lexington County Clerk of Court’s Office.  This case can be re-filed; however, SCANA and SCE&G 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, SCANA and SCE&G were served with a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation. The case was filed in South Carolina's Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges that SCANA and SCE&G made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCANA’s and SCE&G’s electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. The plaintiff did not assert a specific dollar amount for the claims. SCANA and SCE&G believe their actions are consistent with governing law and the applicable documents granting easements and rights-of-way. The Circuit Court granted SCANA’s and SCE&G’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 overruled the Circuit Court in October 2006 and returned the case to the Circuit Court for further consideration.  In July 2007, the Circuit Court issued a ruling that limits the plaintiff’s purported class to owners of easements situated in Charleston County, South Carolina.  The plaintiff has appealed this ruling to the South Carolina Court of Appeals.  It is anticipated that this case may not go to trial before 2008.  SCANA and SCE&G will continue to mount a vigorous defense and believe that the resolution of these claims will not have a material adverse impact on their 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 sought restitution to all affected customers and penalties of up to $5,000 for each separate violation. The claim against SCE&G 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 a material adverse impact on the Company’s results of 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.

Gas Transmission is comprised of Carolina Gas Transmission Corporation (CGTC) which, effective November 1, 2006, began operating as an open access, transportation-only interstate pipeline company regulated by FERC.  For prior periods, Gas Transmission was comprised of South Carolina Pipeline Corporation (SCPC).  Effective November 1, 2006, SCG Pipeline, Inc. (SCG Pipeline) (previously reported in All Other) was merged into SCPC and the company’s name was changed to CGTC.  Prior to the merger, SCPC purchased, transported and sold natural gas intrastate and SCG Pipeline transported natural gas interstate.  The results of CGTC, SCPC and SCG Pipeline appear in the Gas Transmission segment for all periods presented.

	External			Intersegment			Operating			Net			Segment
Millions of dollars	Revenue			Revenue			Income (Loss)			Income (Loss)			Assets
Three Months Ended June 30, 2007
Electric Operations		$	470		$	2		$	110			n/a
Gas Distribution			189			-			(1	)		n/a
Gas Transmission			2			9			4			n/a
Retail Gas Marketing			102			-			n/a		$	2
Energy Marketing			244			47			n/a			1
All Other			(6	)		83			n/a			(5	)
Adjustments/Eliminations			6			(141	)		3			57
Consolidated Total		$	1,007		$	-		$	116		$	55

Six Months Ended June 30, 2007
Electric Operations	$	913		$	4		$	166		n/a		$	5,746
Gas Distribution		622			-			73		n/a			1,801
Gas Transmission		5			20			9		n/a			285
Retail Gas Marketing		343			-			n/a	$	20			140
Energy Marketing		487			112			n/a		1			121
All Other		12			168			n/a		(9	)		550
Adjustments/Eliminations		(12	)		(304	)		31		128			1,019
Consolidated Total	$	2,370		$	-		$	279	$	140		$	9,662

	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			74			9			n/a
Retail Gas Marketing			91			-			n/a		$	3
Energy Marketing			177			20			n/a			(1	)
All Other			13			77			n/a			1
Adjustments/Eliminations			(13	)		(174	)		1			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		229		18		n/a		363
Retail Gas Marketing		362		-		n/a	$	24		151
Energy Marketing		382		31		n/a		(1)		91
All Other		29		150		n/a		(3)		514
Adjustments/Eliminations		(29)		(414)		26		136		1,173
Consolidated Total	$	2,333	$	-	$	308	$	156	$	9,398

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, 2006.

RESULTS OF OPERATIONS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2007

AS COMPARED TO THE CORRESPONDING PERIODS IN 2006

Earnings Per Share

The Company's earnings are reported 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
	2007		2006		2007		2006
Reported (GAAP) earnings per share:	$	.47	$	.50	$	1.20	$	1.35
Deduct:
Cumulative effect of accounting change, net of taxes		-		-		-		.05
Reduction in propane litigation accrual upon settlement		-		.04		-		.04
GAAP-adjusted net earnings per share from operations	$	.47	$	.46	$	1.20	$	1.26

Discussion of adjustments

The cumulative effect of accounting change resulted from the Company’s adoption of Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004),“Share-Based Payment” (SFAS 123(R)).  The reduction in propane litigation accrual resulted from the propane litigation being settled for an amount that was less than had been accrued previously.  This reduction appears in the income statement as a reduction to other expenses.

Management believes that these adjustments are appropriate in determining the non-GAAP financial performance measure. Management utilizes such measure in exercising budgetary control, managing business operations and determining eligibility for certain 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 cumulative effect on per share earnings of the accounting change resulting from the Company’s adoption of SFAS 123(R) and of litigation related to the sale of a prior business.

Second Quarter

GAAP-adjusted net earnings per share from operations increased primarily due to a higher gas margin of $.05 and a higher electric margin of $.02.  These increases were partially offset by higher operating expenses of $.06.  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 at Income Taxes - Recognition of Synthetic Fuel Tax Credits.

Year to Date

GAAP-adjusted net earnings per share from operations decreased primarily due to higher operating expenses of $.17 and dilution of $.02.  These decreases were partially offset by higher natural gas margin of $.12 and higher electric margin 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 at Income Taxes - Recognition of Synthetic Fuel Tax Credits.

Dividends Declared

The Company’s Board of Directors has declared the following dividends on common stock during 2007:

Declaration Date	Dividend Per Share	Record Date	Payment Date
February 15, 2007	$.44	March 9, 2007	April 1, 2007
April 26, 2007	.44	June 11, 2007	July 1, 2007
August 2, 2007	.44	September 10, 2007	October 1, 2007

Electric Operations

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

	Second Quarter						Year to Date
Millions of dollars		2007	% Change			2006			2007	% Change			2006
Operating revenues	$	470.0	2.0	%	$	460.8		$	912.7	6.2	%	$	859.5
Less:  Fuel used in generation		152.9	4.3	%		146.6			308.8	16.9	%		264.1
Purchased power		6.6	(19.5)	%		8.2			18.0	51.3	%		11.9
Margin	$	310.5	1.5	%	$	306.0		$	585.9	0.4	%	$	583.5

*Greater than 100%

Second Quarter

Margin increased by $11.1 million due to customer growth and usage.  This increase was partially offset by $5.6 million due to lower off-system sales.

Year to Date

Margin increased by $19.1 million due to customer growth and usage.  This increase was partially offset by $16.3 million due to lower off-system sales.

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 margin (including transactions with affiliates) was as follows:

	Second Quarter						Year to Date
Millions of dollars		2007	% Change			2006			2007	% Change			2006
Operating revenues	$	189.5	14.6	%	$	165.4		$	622.5	1.8	%	$	611.2
Less: Gas purchased for resale		133.4	10.2	%		121.0			436.9	(4.3)	%		456.7
Margin	$	56.1	26.4	%	$	44.4		$	185.6	20.1	%	$	154.5

Second Quarter

Margin at SCE&G increased by $3.3 million due to the Public Service Commission of South Carolina (SCPSC)-approved increase to retail gas base rates effective with the first billing cycle in November 2006 and by $1.9 million due to customer growth.  Margin at PSNC Energy increased by $ 3.9 million due to the North Carolina Utilities Commission (NCUC)-approved rate increase effective for services rendered on or after November 1, 2006 and by $1.6 million due to customer growth and usage.

Year to Date

Margin at SCE&G increased by $10.8 million due to the SCPSC-approved increase to retail gas base rates and by $2.2 million due to customer growth.  Margin at PSNC Energy increased by $ 9.1 million due to the NCUC-approved rate increase effective for services rendered on or after November 1, 2006 and by $6.2 million due to customer growth and usage.

Gas Transmission

Gas Transmission is comprised of the operations of Carolina Gas Transmission Corporation (CGTC) and, for periods prior to the name change and merger, South Carolina Pipeline Corporation and SCG Pipeline, Inc., for all periods presented. Gas transmission sales margin (including transactions with affiliates) was as follows:

	Second Quarter						Year to Date
Millions of dollars		2007	% Change			2006			2007	% Change			2006
Transportation revenue	$	11.3	*		$	5.5		$	23.5	*		$	10.9
Other operating revenues		0.6	**			118.1			1.5	**			336.3
Less: Gas purchased for resale		-	**			107.3			-	**			313.8
Margin	$	11.9	(27.0)	%	$	16.3		$	25.0	(25.1)	%	$	33.4

*Greater than 100%

** Change not meaningful due to change in business model.

Second Quarter and Year to Date

      Transportation revenue increased as a result of the change to an open access, transportation-only interstate pipeline business model effective November 1, 2006.  As a result of this change, CGTC no longer earns commodity gas revenues, nor does it incur gas cost.

Retail Gas Marketing

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

	Second Quarter						Year to Date
Millions of dollars		2007	% Change			2006			2007	% Change			2006
Operating revenues	$	102.2	12.1	%	$	91.2		$	343.0	(5.3	)%	$	362.1
Net income	$	1.4	(39.1	)%	$	2.3		$	19.7	(16.9	)%	$	23.7

Second Quarter

Operating revenues increased primarily as a result of higher average retail prices which were partially offset by lower volume. Net income decreased primarily due to higher expenses, including bad debt expense, and lower margin.

Year to Date

Operating revenues decreased primarily as a result of lower average retail prices which were partially offset by higher volume.  Net income decreased primarily due to higher expenses, including bad debt expense, and lower margin.

Energy Marketing

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

	Second Quarter						Year to Date
Millions of dollars		2007	% Change			2006			2007	% Change			2006
Operating revenues	$	288.0	45.6	%	$	197.8		$	593.1	43.5	%	$	413.4
Net income (loss)	$	0.8	*		$	(0.6)		$	0.8	*		$	(0.6)

*Greater than 100%

Second Quarter

Operating revenues increased primarily due to customer growth, some of which results from customers formerly reported in the Gas Transmission segment now being reported in Energy Marketing.  Net income increased primarily due to higher margins.

Year to Date

Operating revenues increased primarily due to customer growth, some of which results from customers formerly reported in the Gas Transmission segment now being reported in Energy Marketing.  Net income increased primarily due to higher margins of $1.7 million, which were partially offset by increased operating expenses of $0.6 million.

Other Operating Expenses

Other operating expenses arising from the operating segments previously discussed were as follows:

	Second Quarter						Year to Date
Millions of dollars		2007	% Change			2006			2007	% Change			2006
Other operation and maintenance	$	160.1	6.7	%	$	150.1		$	334.1	9.0	%	$	306.6
Depreciation and amortization		85.8	11.3	%		77.1			176.9	15.4	%		153.3
Other taxes		38.5	3.5	%		37.2			79.4	4.6	%		75.9

Second Quarter

Other operation and maintenance expenses increased primarily due to higher incentive compensation and other benefit costs.  Depreciation and amortization expense increased by $5.9 million due to lower estimated phase-out of synthetic fuel tax credits related to the back-up dam at Lake Murray (see Income Taxes-Recognition of Synthetic Fuel Tax Credits) and by $2.5 million due to net property additions.  Other taxes increased due to higher property taxes.

Year to Date

Other operation and maintenance expenses increased by $8.5 million due to higher electric generation, transmission and distribution expenses, by $9.6 million due to higher incentive compensation and other benefit costs and by $4.0 million due to higher bad debt expense.  Depreciation and amortization expense increased by $17.8 million due to lower estimated phase-out of synthetic fuel tax credits related to the back-up dam at Lake Murray (see Income Taxes-Recognition of Synthetic Fuel Tax Credits) and by $4.9 million due to net property additions.  Other taxes increased due to higher property taxes.

Other Income (Expense)

Other income (expense) includes the results of certain incidental (non-utility) activities and the activities of certain non-regulated subsidiaries. Other income (expense) declined in 2007 compared to 2006 primarily due to lower carrying cost recovery recognition on the unrecovered balance of the Lake Murray back-up dam project.

Income Taxes

Income tax expense decreased primarily due to changes in operating income and due to the recognition at SCE&G of $18.5 million in synthetic fuel tax credits during the first half of 2007 compared to $8.8 million during the same period in 2006. 

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 methodology approved by SCPSC in a January 2005 order, construction costs related to the Lake Murray back-up dam project are 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 declines as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, they can have a significant impact on individual line items within the income statement. The 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, 2007 and 2006 are as follows:

		Second Quarter					Year to Date
Millions of dollars		2007			2006		2007		2006
Depreciation and amortization expense	$	(7.1	)	$	(1.2	)	$	(19.1)	$	(1.4	)
Income tax benefits:
From synthetic fuel tax credits		6.8			3.3			17.7		6.6
From accelerated depreciation		2.7			0.5			7.3		0.6
From partnership losses		1.5			1.5			3.6		3.5
Total income tax benefits		11.0			5.3			28.6		10.7
Losses from Equity Method Investments		(3.9	)		(4.1	)		(9.5)		(9.3	)
Impact on Net Income	$	-		$	-		$	-	$	-

Depreciation on the Lake Murray back-up dam remediation account will be matched to available synthetic fuel tax credits on a quarterly basis until all of the available synthetic fuel tax credits have been utilized. The synthetic fuel tax credit program expires at the end of 2007.

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

The benchmark price range for 2006, published in April 2007, is $55 to $69 per barrel, resulting in a phase-out of 33 percent for 2006. SCE&G’s analysis indicates that the available synthetic fuel tax credits for 2007 also are likely to be impacted by the phase-out calculation. As such, through June 2007 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 74.5 percent of credits generated in 2007 will be available (phase-out of 25.5 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 2007. The availability of these synthetic fuel tax credits is also subject to coal availability and other operational risks related to the generating plants.

The Company does not expect available credits to be sufficient to fully recover the construction costs of dam remediation, and the total unrecovered cost at the end of 2007 may be significant. To the extent 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 will likely be sought. As of June 30, 2007, remaining unrecovered costs, based on management’s recording of accelerated depreciation and related tax benefits, were $54.0 million.

Finally, SCANA, through a subsidiary, 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 SCANA receives for these services.

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its contractual cash obligations will be met through internally generated funds, the incurrence of additional short- and long-term indebtedness and sales of 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 ratios of earnings to fixed charges for the six and 12 months ended June 30, 2007 were 2.68 and 2.78, respectively.

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.

SCE&G expects to add additional base load electric generation in the 2015 to 2016 timeframe.  Based on an evaluation of alternatives, SCE&G and Santee Cooper, a state-owned utility in South Carolina (joint owners of Summer Station) have selected the Summer Station site as the preferred site for new nuclear generation. 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. While SCE&G’s current plans are to pursue the development of one or both of these nuclear units, these plans will continue to be influenced by many factors, including NRC licensing attainment, ongoing evaluation of relative construction and operating costs, the cost of competing fuels, regulatory and environmental requirements and financial market conditions.

In May 2007, the Base Load Review Act (the Act) became law in South Carolina.  This law is intended to allow a utility to recover prudently incurred capital and operating costs associated with new nuclear or coal-fired base load electric generating facilities larger than 350 megawatts.  Based on an application filed by the utility under the Act, the SCPSC would review and rule on the prudency of the decision to build the plant.  If the decision was found to be prudent, that finding would be binding on all future proceedings so long as the plant is constructed in accordance with the schedules, estimates and projections set forth in the approved application.  In addition, beginning with the initial proceeding, the utility would be allowed to file revised rates with the SCPSC each year to incorporate any nuclear construction work in progress incurred.  Requested rate adjustments would be based on the utility’s updated cost of debt and capital structure.  The cost of service and rate design would be based on the rates approved in the utility’s most recent electric rate order.  The utility may choose to file for a project-specific return on common equity or use the return from its most recent rate proceeding if the proceeding is less than five years old.

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

On February 15, 2007, SCANA redeemed at maturity $25 million of its medium-term notes which bore interest at 6.9%.

In June 2007 SCANA entered into an agreement to issue and sell Floating Rate Senior Notes due June 1, 2034, in an aggregate principal amount of between $90 million and $110 million.  The notes are to be issued at intervals between December 2007 and June 2009.  The proceeds of the notes will be used for general corporate purposes including financing the construction and development of headquarters facilities.  At June 30, 2007 SCANA had not issued any notes pursuant to the agreement.

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.

ENVIRONMENTAL AND REGULATORY MATTERS

The EPA has undertaken an aggressive enforcement initiative and the United States Department of Justice (DOJ) has brought suit against a number of utilities in federal court alleging violations of the Clean Air Act (CAA). At least two of these suits have either been tried or have had substantive motions decided—neither favorable to the industry. One of the decisions is not believed to be binding as precedent and the other one, described more fully below, may be.

On April 2, 2007, in a unanimous ruling, the U.S. Supreme Court vacated a decision by the U.S. Court of Appeals for the Fourth Circuit that effectively halted the EPA enforcement action against Duke Energy Corporation (Duke) for allegedly performing plant modifications without a required permit.  Such modifications for life extension and modernization as performed by Duke and other utilities, including SCE&G, were common within the industry.  Hence this decision may heighten the potential exposure of utilities to enforcement actions such as those already brought against Duke and others, many of which had not proceeded pending this Supreme Court decision.

 Although the Supreme Court overturned the lower courts’ decisions, some issues were not ruled upon and were remanded to the lower courts where they may receive further consideration.  Several arguments are expected to continue during the remand proceedings. For example, Duke argued that the EPA has taken inconsistent positions in its interpretations of “routine maintenance, repair and replacement” and is now “retroactively targeting twenty years of accepted practice.” The Supreme Court noted that this issue was not addressed by the lower court decisions, and, to the extent it is not procedurally foreclosed, Duke may raise it on remand.  

Prior to the suits, those utilities had received requests for information under Section 114 of the CAA and were issued Notices of Violation. The basis for these suits is the assertion by the EPA, under a stringent rule known as New Source Review (NSR), that certain maintenance activities undertaken by the utilities constitute “major modifications” which would have required the installation of costly Best Available Control Technology (BACT). SCE&G and GENCO have previously received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. The regulations under the CAA provide certain exemptions to the definition of “major modifications,” including an exemption for routine repair, replacement or maintenance. On October 27, 2003, the EPA published a final revised NSR rule in the Federal Register with an effective date of December 26, 2003. The rule represents an industry-favorable departure from certain positions advanced by the federal government in the NSR enforcement initiative. However, on motion of several Northeastern states, the United States Circuit Court of Appeals for the District of Columbia stayed the effect of the final rule. Even with the recent Supreme Court action described above, the ultimate application of the final rule to the Company is uncertain. The Company has analyzed each of the activities covered by the EPA’s requests and believes each of these activities is covered by the exemption for routine repair, replacement and maintenance under what it believes is a fair reading of both the prior regulation and the contested revised regulation. The regulations also provide an exemption for an increase in emissions resulting from increased hours of operation or production rate and from demand growth.

The current state of continued DOJ enforcement actions continues to be the subject of industry-wide speculation, but it is possible that the EPA will commence enforcement actions against SCE&G and GENCO, and the EPA has the authority to seek penalties at the rate of up to $27,500 per day for each violation. The EPA also could seek installation of BACT (or equivalent) at the three plants. The Company continues to believe that any enforcement actions relative to the Company’s compliance with the CAA would be without merit. The Company has completed installation of selective catalytic reactors at Wateree and Williams for nitrogen oxides control and is proceeding with plans to install sulfur dioxide scrubbers at both of these stations to meet Clean Air Interstate Rule (CAIR) regulations. These actions would mitigate many of the concerns with NSR. SCE&G and GENCO expect to incur capital expenditures totaling approximately $450 million over the 2007-2010 period to install this new equipment. SCE&G and GENCO also expect to have increased operation and maintenance costs related to this equipment of approximately $3.4 million in 2009 and $23 million in 2010 and each subsequent year thereafter. To meet compliance requirements for the years 2012 through 2016, the Company anticipates additional capital expenditures totaling approximately $480 million.

See notes to the condensed consolidated financial statements for additional information related to environmental matters (Note 5B) and regulatory matters (Note 2).

OTHERS MATTERS

In June 2007 the Georgia Public Service Commission (GPSC) announced that SCANA Energy will continue to serve as Georgia’s regulated provider of natural gas until August 31, 2009 with an option for a third year if approved by the GPSC.  SCANA Energy has been Georgia’s regulated provider since the program began in 2002.  At June 30, 2007 SCANA Energy’s regulated division served approximately 98,000 customers.

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, 2007	Expected Maturity
						There-		Fair
Millions of dollars	2007	2008	2009	2010	2011	After	Total	Value
Long-Term Debt Issued:
Fixed Rate ($)	5.0	123.2	108.2	14.8	619.3	2,023.6	2,894.1	2,991.7
Average Fixed Interest Rate (%)	7.51	5.96	6.27	6.87	6.78	5.95	6.15	n/a
Variable Rate ($)		100.0					100.0	100.2
Average Variable Interest Rate (%)		5.51					5.51	n/a
Interest Rate Swap:
Pay Variable/Receive Fixed ($)	-	3.2	3.2	3.2	3.2	3.2	16.0	-
Average Pay Interest Rate (%)	-	8.55	8.55	8.55	8.55	8.55	8.55	n/a
Average Receive Interest Rate (%)	-	8.75	8.75	8.75	8.75	8.75	8.75	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.

In June 2007 SCANA entered into an agreement to issue and sell Floating Rate Senior Notes due June 1, 2034, in an aggregate principal amount of between $90 million and $110 million.  The notes are to be issued at intervals between December 2007 and June 2009.  At June 30, 2007 the estimated fair value of the Company’s forward starting interest rate swap related to the Floating Rate Senior Notes totaled $0.3 million (gain).  These notes and the swap are not depicted in the table above.

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:
	Futures Contracts			Options
				Purchased Call	Sold Call	Sold Put
2007	Long	Short			(Short)	(Long)
Settlement Price (a)	7.55	7.91	Strike Price (a)	8.75	12.23	6.13
Contract Amount (b)	13.9	1.1	Contract Amount (b)	5.1	1.3	0.5
Fair Value (b)	12.8	1.0	Fair Value (b)	0.4	-	-
2008
Settlement Price (a)	8.63	-	Strike Price (a)	9.33	14.00	-
Contract Amount (b)	30.1	-	Contract Amount (b)	6.1	1.4	-
Fair Value (b)	29.5	-	Fair Value (b)	0.7	-	-
(a)   Weighted average, in dollars
(b)  Millions of dollars

	Expected Maturity
Swaps	2007	2008	2009
Commodity Swaps:
Pay fixed/receive variable (b)	105.4	150.6	13.7
Average pay rate (a)	8.8068	9.2045	9.8157
Average received rate (a)	7.6304	8.6376	9.4054
Fair value (b)	91.3	141.3	13.1
Pay variable/receive fixed (b)	1.8	3.2	52.0
Average pay rate (a)	7.3546	8.6194	7.9980
Average received rate (a)	8.2571	8.8361	7.2500
Fair value (b)	2.0	3.3	-
Basis Swaps:
Pay variable/receive variable (b)	13.0	10.7	4.2
Average pay rate (a)	7.4637	8.6075	8.6548
Average received rate (a)	7.4555	8.5897	8.6124
Fair value (b)	13.0	10.7	4.1
(a)   Weighted average, in dollars
(b)  Millions of dollars

As of June 30, 2007, SCANA Corporation (SCANA) conducted an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of (a) the effectiveness of the design and operation of its disclosure controls and procedures and (b) any change in its internal control over financial reporting. Based on this evaluation, the CEO and CFO concluded that, as of June 30, 2007, SCANA’s disclosure controls and procedures were effective. There has been no change in SCANA’s internal control over financial reporting during the quarter ended June 30, 2007 that has materially affected or is reasonably likely to materially affect SCANA’s internal control over financial reporting.

FINANCIAL SECTION

ITEM 1. FINANCIAL STATEMENTS

SOUTH CAROLINA ELECTRIC & GAS COMPANY

(Unaudited)

	June 30,			December 31,
Millions of dollars	2007			2006
Assets
Utility Plant In Service	$	8,106		$	7,876
Accumulated Depreciation and Amortization		(2,578	)		(2,483	)
		5,528			5,393
Construction Work in Progress		294			316
Nuclear Fuel, Net of Accumulated Amortization		66			39
Utility Plant, Net		5,888			5,748
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation		32			31
Assets held in trust, net - nuclear decommissioning		58			56
Other investments		25			25
Nonutility Property and Investments, Net		115			112
Current Assets:
Cash and cash equivalents		15			24
Receivables, net of allowance for uncollectible accounts of $6 and $5		307			311
Receivables - affiliated companies		28			41
Inventories (at average cost):
Fuel		147			147
Materials and supplies		90			85
Emission allowances		43			22
Prepayments and other		25			20
Deferred income taxes		18			19
Total Current Assets		673			669
Deferred Debits and Other Assets:
Pension asset, net		212			200
Due from affiliates - pension and postretirement benefits		44			41
Emission allowances		-			27
Regulatory assets		678			702
Other		100			127
Total Deferred Debits and Other Assets		1,034			1,097
Total	$	7,710		$	7,626

	June 30,		December 31,
Millions of dollars	2007		2006
Capitalization and Liabilities
Shareholders’ Investment:
Common equity	$	2,537	$	2,457
Preferred stock (Not subject to purchase or sinking funds)		106		106
Total Shareholders’ Investment		2,643		2,563
Preferred Stock, net (Subject to purchase or sinking funds)		7		8
Long-Term Debt, net		2,005		2,008
Total Capitalization		4,655		4,579
Minority Interest		87		86
Current Liabilities:
Short-term borrowings		415		362
Current portion of long-term debt		13		14
Accounts payable		103		155
Accounts payable - affiliated companies		164		147
Customer deposits and customer prepayments		41		40
Taxes accrued		83		112
Interest accrued		34		33
Dividends declared		42		23
Other		41		63
Total Current Liabilities		936		949
Deferred Credits and Other Liabilities:
Deferred income taxes, net		800		807
Deferred investment tax credits		103		118
Asset retirement obligations		287		279
Postretirement benefits		197		194
Due to affiliates - pension and postretirement benefits		6		6
Regulatory liabilities		571		541
Other		68		67
Total Deferred Credits and Other Liabilities		2,032		2,012
Commitments and Contingencies (Note 4)		-		-
Total	$	7,710	$	7,626

See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Millions of dollars	2007			2006			2007			2006
Operating Revenues:
Electric	$	472		$	464		$	917		$	864
Gas		103			89			292			281
Total Operating Revenues		575			553			1,209			1,145
Operating Expenses:
Fuel used in electric generation		153			147			309			264
Purchased power		7			8			18			12
Gas purchased for resale		81			72			220			225
Other operation and maintenance		116			114			246			229
Depreciation and amortization		74			65			153			130
Other taxes		35			34			73			69
Total Operating Expenses		466			440			1,019			929
Operating Income		109			113			190			216
Other Income (Expense):
Other income		7			5			13			44
Other expenses		(2	)		(1	)		(6	)		(36	)
Interest charges, net of allowance for borrowed funds
used during construction of $3, $2, $5 and $3		(35	)		(36	)		(71	)		(72	)
Gain on sale of assets		-			-			1			-
Allowance for equity funds used during construction		1			-			1			-
Total Other Expense		(29	)		(32	)		(62	)		(64	)
Income Before Income Taxes, Losses from Equity
Method Investments, Minority Interest, Cumulative Effect of
Accounting Change and Preferred Stock Dividends		80			81			128			152
Income Tax Expense		20			23			23			41
Income Before Losses from Equity Method Investments,
Minority Interest, Cumulative Effect of Accounting Change
and Preferred Stock Dividends		60			58			105			111
Losses from Equity Method Investments		(4	)		(4	)		(10	)		(10	)
Minority Interest		2			1			4			3
Cumulative Effect of Accounting Change, net of taxes		-			-			-			4
Net Income		54			53			91			102
Preferred Stock Cash Dividends Declared		2			2			4			4
Earnings Available for Common Shareholder	$	52		$	51		$	87		$	98
See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

(Unaudited)

	Six Months Ended
	June 30,
Millions of dollars	2007			2006
Cash Flows From Operating Activities:
Net income	$	91		$	102
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			10
Minority interest		4			3
Depreciation and amortization		152			130
Amortization of nuclear fuel		9			9
Carrying cost recovery		(1	)		(4	)
Gain of sale of assets		(1	)		-
Cash provided (used) by changes in certain assets and liabilities:
Receivables, net		(5	)		41
Inventories		(27	)		(28	)
Prepayments		(5	)		(11	)
Pension asset		(11	)		(7	)
Other regulatory assets		6			11
Deferred income taxes, net		(6	)		13
Regulatory liabilities		16			18
Postretirement benefits		3			4
Accounts payable		(17	)		(41	)
Taxes accrued		(29	)		(47	)
Interest accrued		1			(1	)
Changes in fuel adjustment clauses		1			29
Changes in other assets		20			11
Changes in other liabilities		(25	)		(1	)
Net Cash Provided From Operating Activities		186			237
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(261	)		(181	)
Non-utility property additions		(1	)		-
Proceeds from sale of assets		1			-
Short-term investments-affiliate		10			-
Investments		(9	)		(17	)
Net Cash Used For Investing Activities		(260	)		(198	)
Cash Flows From Financing Activities:
Proceeds from issuance of debt		-			123
Repayment of debt		(4	)		(8	)
Retirement of preferred stock		(1	)		-
Dividends		(61	)		(79	)
Contribution from parent		66			3
Short-term borrowings - affiliate, net		12			4
Short-term borrowings, net		53			(88	)
Net Cash Provided From (Used For) Financing Activities		65			(45	)
Net Decrease In Cash and Cash Equivalents		(9	)		(6	)
Cash and Cash Equivalents, January 1		24			19
Cash and Cash Equivalents, June 30	$	15		$	13
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $5 and $3)	$	67		$	2
- Income taxes		6			31
Noncash Investing and Financing Activities:
Accrued construction expenditures		26			14
See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

June 30, 2007

(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, 2006. 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 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 emission allowances. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of $274 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	2007		2006
Regulatory Assets:
Accumulated deferred income taxes	$	169	$	169
Under-collections-electric fuel and gas cost adjustment clauses		31		49
Deferred purchased power costs		4		9
Environmental remediation costs		17		18
Asset retirement obligations and related funding		261		254
Franchise agreements		52		55
Deferred regional transmission organization costs		7		8
Deferred employee benefit plan costs		124		128
Other		13		12
Total Regulatory Assets	$	678	$	702

Regulatory Liabilities:
Accumulated deferred income taxes	$	32	$	34
Over-collection - gas cost adjustment clause		8		-
Other asset removal costs		455		438
Storm damage reserve		47		44
Planned major maintenance		9		6
Other		20		19
Total Regulatory Liabilities	$	571	$	541

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) during annual hearings. Included in these amounts are regulatory assets or liabilities arising from realized and unrealized gains and losses incurred in the natural gas hedging program of the Company’s regulated operations.

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

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.  SCE&G is authorized to amortize $1.4 million of these costs on an annual basis.

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 electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years.

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

Deferred employee benefit plan costs represent pension and other postretirement benefit costs which were accrued as liabilities under provision of SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” but which are expected to be recovered through utility rates.

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

The storm damage reserve represents an SCPSC-approved collection through electric rates capped at $50 million, which 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, 2007, no amounts were drawn from this reserve.

Planned major maintenance related to certain fossil hydro turbine/generation 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, beginning in January 2005, through electric rates to offset turbine maintenance expenditures.  Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.

The SCPSC has reviewed and approved through specific orders most of the items shown as regulatory assets.  Other regulatory assets represent costs which have not been 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.      Affiliated Transactions

CGTC transports natural gas to SCE&G to supply certain electric generation requirements and to serve SCE&G’s retail gas customers.  SCE&G had approximately $2.0 million payable to CGTC for transportation services at June 30, 2007 and $1.9 million payable at December 31, 2006.

SCE&G purchases natural gas and related pipeline capacity from SCANA Energy Marketing, Inc. (SEMI) to supply its Jasper County Electric Generating Station and to serve its retail gas customers.  Such purchases totaled $47.4 million and $111.9 million for the three and six months ended June 30, 2007, respectively, and totaled $16.3 million and $23.3 million for the three and six months ended June 30, 2006, respectively. SCE&G’s payables to SEMI for such purposes were $19.1 million at June 30, 2007 and $15.4 million at December 31, 2006.

Total interest expense, based on market interest rates, associated with the Company’s borrowings from affiliated companies was $1.3 million and $2.2 million for the three and six months ended June 30, 2007, respectively.  Total interest expense for the three and six months ended June 30, 2006 was not significant.  Total interest income from investments with affiliated companies for the three and six months ended June 30, 2007 and 2006 also was not significant.  At June 30, 2007 and December 31, 2006, SCE&G owed an affiliate $75 million arising from advances from a consolidated cash management utility money pool.

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 $28.4 million at June 30, 2007 and $31.8 million at December 31, 2006.  SCE&G’s payables to these affiliated companies were $26.6 million at June 30, 2007 and $26.6 million at December 31, 2006.

SCE&G purchases shaft horsepower from a cogeneration facility.  The facility is owned by a limited liability company (LLC) in which SCANA holds an equity-method investment.  SCE&G’s payables to the LLC were $2.4 million at June 30, 2007 and $2.5 million at December 31, 2006.  SCE&G purchased $6.1 million and $13.4 million of shaft horsepower from the LLC for the three and six months ended June 30, 2007, respectively, and purchased $6.4 million and $12.7 million of shaft horsepower from the LLC for the three and six months ended June 30, 2006, respectively.

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
Three months ended June 30,	2007			2006			2007			2006
Millions of dollars
Service cost	$	3.5		$	3.5		$	1.2		$	1.2
Interest cost		10.4			9.9			3.0			2.8
Expected return on assets		(20.1	)		(18.8	)		-			-
Prior service cost amortization		1.7			1.7			0.3			0.2
Transition obligation amortization		-			0.1			0.2			0.2
Amortization of actuarial loss		-			0.2			0.3			0.4
Amount attributable to Company affiliates		(0.6	)		(0.6	)		(1.3	)		(1.3	)
Net periodic benefit (income) cost	$	(5.1	)	$	(4.0	)	$	3.7		$	3.5

	Pension Benefits						Other Postretirement Benefits
Six months ended June 30,	2007			2006			2007			2006
Millions of dollars
Service cost	$	7.0		$	7.0		$	2.4		$	2.4
Interest cost		20.7			19.8			6.0			5.6
Expected return on assets		(40.2	)		(37.6	)		-			-
Prior service cost amortization		3.4			3.4			0.6			0.4
Transition obligation amortization		-			0.2			0.4			0.4
Amortization of actuarial loss		-			0.4			0.6			0.7
Amount attributable to Company affiliates		(1.1	)		(1.2	)		(2.7	)		(2.6	)
Net periodic benefit (income) cost	$	(10.2	)	$	(8.0	)	$	7.3		$	6.9

E.       New Accounting Matters

SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” was issued in February 2007. SFAS 159 allows entities to measure at fair value many financial instruments and certain other assets and liabilities that are not otherwise required to be measured at fair value. SFAS 159 is effective for fiscal years beginning after November 15, 2007. The Company has not determined what impact, if any, that adoption will have on the Company’s results of operations, cash flows or financial position.

SFAS 157, “Fair Value Measurements,” was issued in September 2006.  SFAS 157 establishes a framework for measuring fair value to increase the consistency and comparability in fair value measurements.  The Company will adopt SFAS 157 in the first quarter of 2008, and has not determined what impact, if any, that adoption will have on the Company’s results of operations, cash flows or financial position.

FIN 48, “Accounting for Uncertainty in Income Taxes,” 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 financial statement recognition threshold and measurement attributes for tax positions taken or expected to be taken in tax returns. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company adopted FIN 48 in the first quarter of 2007.  The impact on the Company’s results of operations, cash flows or financial position is discussed at Note 1F.

FASB Staff Position (FSP) AUG AIR-1 “Accounting for Planned Major Maintenance Activities,” amended APB 28, “Interim Financial Reporting,” to prohibit the use of the accrue-in-advance method of accounting for planned major maintenance.  As disclosed in Note 1A, SCE&G has received specific SCPSC orders providing for use of accrue-in-advance accounting for certain planned major maintenance activities. Accordingly, SCE&G will continue to follow accrue-in-advance accounting as allowed under SFAS 71 for these activities. The Company’s adoption of FSP AUG AIR-1 in the first quarter of 2007 had no impact on the Company’s results of operations, cash flows or financial position.

F.       Income Taxes

The Company is included in the  consolidated federal income tax return of SCANA Corporation (SCANA) and files in various state and local jurisdictions.  The Internal Revenue Service (IRS) has completed examinations of SCANA’s federal returns through 2004, and SCANA’s federal tax returns through 2001 are closed for additional assessment.  On July 30, 2007, the statute of limitations for the 2002 federal return expired, but no material changes resulted.  With a few exceptions, the Company is no longer subject to state and local income tax examinations by tax authorities for years before 2003.  The IRS has completed the examination of S. C. Coaltech No. 1 LP., a synthetic fuel partnership in which SCE&G has an interest, for the 2004 tax year.  SCE&G does not anticipate that any adjustments from the examination will have a material impact on the earnings, cash flows or the financial position of SCE&G.  SCE&G continues to believe that all of its synthetic fuel tax credits have been properly claimed.

In connection with the initial adoption of FIN 48 effective January 1, 2007, SCE&G removed $15 million of previously recognized tax benefits from its balance sheet.  Because regulatory liabilities had been recorded for these previously recognized tax benefits under the provisions of SFAS 71, these benefits had never been recognized in SCE&G’s earnings or retained earnings.  As a result, the initial adoption of FIN 48 had no effect on SCE&G’s equity.  The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $15 million.  Because the benefits would be amortized into earnings over a number of years under SFAS 71, the impact on any individual year’s effective tax rate would be immaterial.  No material changes in the status of our tax positions have occurred subsequent to adoption.

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  Through June 30, 2007, the Company has not accrued any significant amount of interest or tax penalties.

G.      Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, comprised of the deferred cost of employee benefit plans, totaled $6.9 million as of June 30, 2007 and December 31, 2006.

2.       RATE AND OTHER REGULATORY MATTERS

Electric

On June 15, 2007 SCE&G filed an application with the SCPSC requesting a 6.75% increase in retail electric rates.  The application, among other things, seeks recovery of costs incurred to perform mandatory environmental upgrades to SCE&G’s generating plants.  SCE&G’s application is expected to be heard by the SCPSC in November 2007.  If approved, the new rates would be effective in January 2008.

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

Gas

On June 15, 2007 SCE&G filed an application with the SCPSC requesting an increase in retail natural gas rates of 1.3% under the terms of the Natural Gas Rate Stabilization Act (Stabilization Act).  The Stabilization Act is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas service infrastructure.  The SCPSC is expected to review SCE&G’s filing in October 2007.  If approved, the rate adjustment would be implemented with the first billing cycle in November 2007.

In September 2006, the SCPSC approved an increase in retail natural gas rates of 3.2% under the terms of the Stabilization Act.  The rate adjustment was 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 in October 2006 which authorized SCE&G to adjust its cost of gas on a monthly, rather than an annual, basis beginning in December 2006.  The cost of gas adjustment is based on a twelve-month rolling average.

3.      LONG-TERM DEBT

Substantially all of the Company’s electric utility plant is pledged as collateral in connection with long-term debt.

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 SCE&G’s Annual Report on Form 10-K for the year ended December 31, 2006.

The Company’s regulated gas operations hedge natural gas purchasing activities using over-the-counter options and swaps and New York Mercantile Exchange (NYMEX) futures and options. The Company’s tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of 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.

5.       COMMITMENTS AND CONTINGENCIES

Reference is made to Note 10 to the consolidated financial statements appearing in SCE&G’s Annual Report on Form 10-K for the year ended December 31, 2006. Commitments and contingencies at June 30, 2007 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, the one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $14.1 million.

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

B.      Environmental

In March 2005, the United States 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, although compliance plans and cost to comply with the rule have not been determined. Such costs will be material and are expected to be recoverable through rates.

In March 2005, the EPA issued a final rule establishing a mercury emissions cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. 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 53 others, by the EPA as a potentially responsible party (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. The 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.  The EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The site has not been remediated nor has a clean-up 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, net of insurance recoveries, if any, is expected to be recoverable through rates.

SCE&G has been named, along with 29 others, by the EPA as a 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 approximately 1959 to 1986.  During that time, SCE&G occasionally used CTC for the repair of existing transformers, purchase of new transformers and sale of used transformers.  In 1984, the EPA initiated a remediation of PCB-contaminated soil and groundwater at the site.  The EPA reports that it has spent $36 million to date.  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, net of insurance recoveries, if any, is expected to be recoverable through rates.

SCE&G maintains an environmental assessment program to identify and evaluate its current and former MGP sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate 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 clean-up relate solely to regulated operations.  SCE&G defers site assessment and clean-up costs and recovers them through rates (see Note 1). Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $17.2 million at June 30, 2007.  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 2007, with certain monitoring and retreatment activities continuing through 2012. As of June 30, 2007, SCE&G had spent $22.3 million to remediate the site and expects to spend an additional $1.0 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. SCE&G expects to recover any cost arising from the remediation of this site 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 2011. As of June 30, 2007, SCE&G has spent $4.8 million related to these three sites, and expects to spend an additional $11.2 million.  SCE&G expects to recover any cost arising from the remediation of these sites 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 South Carolina Electric & Gas Company in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit.  The plaintiffs subsequently dismissed defendants Duke Energy and Progress Energy and proceeded against SCE&G only. The plaintiffs sought damages for the alleged improper use of electric transmission and distribution easements but did not assert a dollar amount for their claims. Specifically, the plaintiffs alledged 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 utility’s internal use along the electric transmission and distribution line rights-of-way constituted a trespass. On July 20, 2007, Plaintiffs’ counsel filed a Stipulation of Dismissal Without Prejudice with the Lexington County Clerk of Court’s Office.  This case can be re-filed; however, SCANA and SCE&G 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 Circuit 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 overruled the Circuit Court in October 2006 and returned the case to the Circuit Court for further consideration.  In July 2007, the Circuit Court issued a ruling that limits the plaintiff’s purported class to owners of easements situated in Charleston County, South Carolina.  The plaintiff has appealed this ruling to the South Carolina Court of Appeals.  It is anticipated that this case may not go to trial before 2008.  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 sought restitution to all affected customers and penalties of up to $5,000 for each separate violation. The claim against SCE&G 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 a material adverse impact on the Company’s results of 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, earnings available to the common shareholder are 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, 2007
Electric Operations	$	472	$	111			n/a
Gas Distribution		103		-			n/a
All Other		-		-			(4	)
Adjustments/Eliminations		-		(2	)		56
Consolidated Total	$	575	$	109		$	52

Six Months Ended June 30, 2007
Electric Operations	$	917	$	166			n/a		$	5,746
Gas Distribution		292		27			n/a			463
All Other		-		-		$	(10	)		-
Adjustments/Eliminations		-		(3	)		97			1,501
Consolidated Total	$	1,209	$	190		$	87		$	7,710

Three Months Ended June 30, 2006
Electric Operations	$	464	$	119			n/a
Gas Distribution		89		(3	)		n/a
All Other		-		-		$	(4	)
Adjustments/Eliminations		-		(3	)		55
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

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, 2006.

RESULTS OF OPERATIONS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2007

AS COMPARED TO THE CORRESPONDING PERIODS IN 2006

Net Income

Net income was as follows:

		Second Quarter			Year to Date
		2007	2006			2007	2006
Net income	$	53.7	$	52.5	$	91.1	$	102.0

Second Quarter

Net income increased primarily due to a higher gas margin of $3.2 million and a higher electric margin of $1.8 million, partially offset by increased incentive compensation and other benefit costs of $2.5 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 at Income Taxes - Recognition of Synthetic Fuel Tax Credits.

Year to Date

Net income decreased due to  increased electric generation, transmission and distribution expenses of $5.2 million, increased incentive compensation and other benefit costs of $4.7 million, increased depreciation expense of $3.3 million, increased property and other taxes of $2.2 million and the recognition in 2006 of the cumulative effect of an accounting change resulting from SCANA’s adoption of Statement of Financial Accounting Standards  123(R), “Share-Base Payment,” of $3.8 million, partially offset by an increase in gas margin of $8.0 million and an increase in electric margin of $1.2 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 at Income Taxes - Recognition of Synthetic Fuel Tax Credits.

Dividends Declared

The Company’s Board of Directors has declared the following dividends on common stock held by SCANA Corporation (SCANA) during 2007:

Declaration Date	Amount	Quarter Ended	Payment Date
February 15, 2007	$36.0 million	March 31, 2007	April 1, 2007
April 26, 2007	$39.7 million	June 30, 2007	July 1, 2007
August 2, 2007	$39.7 million	September 30, 2007	October 1, 2007

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. (SCFC).  Electric operations sales margin (including transactions with affiliates) was as follows:

		Second Quarter						Year To Date
Millions of dollars		2007	% Change			2006		2007	% Change				2006
Operating revenues	$	472.0	1.7	%	$	464.3	$	916.6		6.1	%	$	863.9
Less: Fuel used in electric generation		152.9	4.3	%		146.6		308.8		16.9	%		264.1
Purchased power		6.6	(19.5)	%		8.2		18.0		51.3	%		11.9
Margin	$	312.5	1.0	%	$	309.5	$	589.8		0.3	%	$	587.9

Second Quarter

Margin increased by $11.1 million due to customer growth and usage.  This increase was partially offset by $5.6 million due to lower off-system sales.

Year to Date

Margin increased by $19.1 million due to customer growth and usage.  This increase was partially offset by $16.3 million due to lower off-system sales.

Gas Distribution

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

		Second Quarter						Year To Date
Millions of dollars		2007	% Change			2006		2007	% Change				2006
Operating revenues	$	103.2	16.2	%	$	88.8	$	292.3		3.8	%	$	281.5
Less: Gas purchased for resale		80.9	13.0	%		71.6		220.3		(2.1	)%		225.1
Margin	$	22.3	29.7	%	$	17.2	$	72.0		27.7	%	$	56.4

Second Quarter

Margin increased by $3.3 million due to the Public Service Commission of South Carolina (SCPSC)-approved increase to retail gas base rates effective with the first billing cycle in November 2006 and by $1.9 million due to customer growth.

Year to Date

Margin increased by $10.8 million due to an SCPSC-approved increase in retail gas base rates and by $2.2 million due to customer growth.

Other Operating Expenses

Other operating expenses were as follows:

		Second Quarter						Year To Date
Millions of dollars		2007	% Change			2006		2007	% Change				2006
Other operation and maintenance	$	116.9	2.7	%	$	113.8	$	246.0		7.6	%	$	228.6
Depreciation and amortization		74.0	12.8	%		65.6		153.2		17.8	%		130.1
Other taxes		35.1	3.2	%		34.0		72.5		5.1	%		69.0

Second Quarter

Other operation and maintenance expenses increased by $4.2 million due to higher incentive compensation and other benefit costs.  This increase was partially offset by lower costs related to injuries and damages claims of $1.2 million.  Depreciation and amortization expense increased by $5.9 million due to lower estimated phase-out of synthetic fuel tax credits related to the back-up dam at Lake Murray (see Income Taxes-Recognition of Synthetic Fuel Tax Credits) and by $2.5 million due to net property additions.  Other taxes increased due to higher property taxes.

Year to Date

Other operation and maintenance expenses increased by $8.5 million due to higher electric generation, transmission and distribution expenses and by $7.6 million due to higher incentive compensation and other benefit costs.  Depreciation and amortization expense increased by $17.8 million due to lower estimated phase-out of synthetic fuel tax credits related to the back-up dam at Lake Murray (see Income Taxes-Recognition of Synthetic Fuel Tax Credits) and by $5.4 million due to net property additions.  Other taxes increased due to higher property taxes.

Other Income (Expense)

Other income (expense) includes the results of certain incidental (non-utility) activities. Other income (expense) declined in 2007 compared to 2006 primarily due to lower carrying cost recovery recognition on the unrecovered balance of the Lake Murray back-up dam project.

Income Taxes

Income tax expense decreased primarily due to changes in operating income and due to the recognition of $18.5 million in synthetic fuel tax credits during the first half of 2007 compared to $8.8 million during the same period in 2006. 

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 methodology approved by the SCPSC in a January 2005 order, construction costs related to the Lake Murray back-up dam project are 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 declines as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, they can have a significant impact on individual line items within the income statement. The 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, 2007 and 2006 are as follows:

		Second Quarter					Year to Date
Millions of dollars		2007			2006		2007		2006
Depreciation and amortization expense	$	(7.1	)	$	(1.2	)	$	(19.1)	$	(1.4	)
Income tax benefits:
From synthetic fuel tax credits		6.8			3.3			17.7		6.6
From accelerated depreciation		2.7			0.5			7.3		0.6
From partnership losses		1.5			1.5			3.6		3.5
Total income tax benefits		11.0			5.3			28.6		10.7
Losses from Equity Method Investments		(3.9	)		(4.1	)		(9.5)		(9.3	)
Impact on Net Income	$	-		$	-		$	-	$	-

Depreciation on the Lake Murray back-up dam remediation account will be matched to available synthetic fuel tax credits on a quarterly basis until all of the available synthetic fuel tax credits have been utilized.  The synthetic fuel tax credit program expires at the end of 2007.

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

The benchmark price range for 2006, published in April 2007, was $55 to $69 per barrel, resulting in a phase-out of 33 percent for 2006.  SCE&G’s analysis indicates that the available synthetic fuel tax credits for 2007 also are likely to be impacted by the phase-out calculation. As such, through June 2007 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 74.5 percent of credits generated in 2007 will be available (phase-out of 25.5 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 2007. The availability of these synthetic fuel tax credits is also subject to coal availability and other operational risks related to the generating plants.

The Company does not expect available credits to be sufficient to fully recover the construction costs of dam remediation, and the total unrecovered costs at the end of 2007 may be significant. To the extent 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 will likely be sought. As of June 30, 2007, remaining unrecovered costs, based on management’s recording of accelerated depreciation and related tax benefits, were $54.0 million.

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its contractual cash obligations will be met through internally generated funds, the incurrence of additional short- and long-term indebtedness and sales of 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 ratios of earnings to fixed charges for the six and 12 months ended June 30, 2007 were 2.63 and 3.09, respectively.  The Company’s ratios of earnings to combined fixed charges and preference dividends for the same periods were 2.44 and 2.87, respectively.

    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.

SCE&G expects to add additional base load electric generation in the 2015 to 2016 timeframe.  Based on an evaluation of alternatives, SCE&G and Santee Cooper, a state-owned utility in South Carolina (joint owners of Summer Station) have selected the Summer Station site as the preferred site for new nuclear generation. 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. While SCE&G’s current plans are to pursue the development of one or both of these nuclear units, these plans will continue to be influenced by many factors, including NRC licensing attainment, ongoing evaluation of relative construction and operating costs, the cost of competing fuels, regulatory and environmental requirements and financial market conditions.

In May 2007, the Base Load Review Act (the Act) became law in South Carolina.  This law is intended to allow a utility to recover prudently incurred capital and operating costs associated with new nuclear or coal-fired base load electric generating facilities larger than 350 megawatts.  Based on an application filed by the utility under the Act, the SCPSC would review and rule on the prudency of the decision to build the plant.  If the decision was found to be prudent, that finding would be binding on all future proceedings so long as the plant is constructed in accordance with the schedules, estimates and projections set forth in the approved application.  In addition, beginning with the initial proceeding, the utility would be allowed to file revised rates with the SCPSC each year to incorporate any nuclear construction work in progress incurred.  Requested rate adjustments would be based on the utility’s updated cost of debt and capital structure.  The cost of service and rate design would be based on the rates approved in the utility’s most recent electric rate order.  The utility may choose to file for a project-specific return on common equity or use the return from its most recent rate proceeding if the proceeding is less than five years old.

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

ENVIRONMENTAL AND REGULATORY MATTERS

The EPA has undertaken an aggressive enforcement initiative and the United States Department of Justice (DOJ) has brought suit against a number of utilities in federal court alleging violations of the Clean Air Act (CAA). At least two of these suits have either been tried or have had substantive motions decided—neither favorable to the industry. One of the decisions is not believed to be binding as precedent and the other one, described more fully below, may be.

 On April 2, 2007, in a unanimous ruling, the U.S. Supreme Court vacated a decision by the U.S. Court of Appeals for the Fourth Circuit that effectively halted the EPA enforcement action against Duke Energy Corporation (Duke) for allegedly performing plant modifications without a required permit.  Such modifications for life extension and modernization as performed by Duke and other utilities, including SCE&G, were common within the industry.  Hence this decision may heighten the potential exposure of utilities to enforcement actions such as those already brought against Duke and others, many of which had not proceeded pending this Supreme Court decision.

Although the Supreme Court overturned the lower courts’ decisions, some issues were not ruled upon and were remanded to the lower courts where they may receive further consideration.  Several arguments are expected to continue during the remand proceedings. For example, Duke argued that the EPA has taken inconsistent positions in its interpretations of “routine maintenance, repair and replacement” and is now “retroactively targeting twenty years of accepted practice.” The Supreme Court noted that this issue was not addressed by the lower court decisions, and, to the extent it is not procedurally foreclosed, Duke may raise it on remand.  

Prior to the suits, those utilities had received requests for information under Section 114 of the CAA and were issued Notices of Violation. The basis for these suits is the assertion by the EPA, under a stringent rule known as New Source Review (NSR), that certain maintenance activities undertaken by the utilities constitute “major modifications” which would have required the installation of costly Best Available Control Technology (BACT). SCE&G and GENCO have previously received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. The regulations under the CAA provide certain exemptions to the definition of “major modifications,” including an exemption for routine repair, replacement or maintenance. On October 27, 2003, the EPA published a final revised NSR rule in the Federal Register with an effective date of December 26, 2003. The rule represents an industry-favorable departure from certain positions advanced by the federal government in the NSR enforcement initiative. However, on motion of several Northeastern states, the United States Circuit Court of Appeals for the District of Columbia stayed the effect of the final rule. Even with the recent Supreme Court action described above, the ultimate application of the final rule to the Company is uncertain. The Company has analyzed each of the activities covered by the EPA’s requests and believes each of these activities is covered by the exemption for routine repair, replacement and maintenance under what it believes is a fair reading of both the prior regulation and the contested revised regulation. The regulations also provide an exemption for an increase in emissions resulting from increased hours of operation or production rate and from demand growth.

The current state of continued DOJ enforcement actions continues to be the subject of industry-wide speculation, but it is possible that the EPA will commence enforcement actions against SCE&G and GENCO, and the EPA has the authority to seek penalties at the rate of up to $27,500 per day for each violation. The EPA also could seek installation of BACT (or equivalent) at the three plants. The Company continues to believe that any enforcement actions relative to the Company’s compliance with the CAA would be without merit. The Company has completed installation of selective catalytic reactors at Wateree and Williams for nitrogen oxides control and is proceeding with plans to install sulfur dioxide scrubbers at both of these stations to meet Clean Air Interstate Rule (CAIR) regulations. These actions would mitigate many of the concerns with NSR. SCE&G and GENCO expect to incur capital expenditures totaling approximately $450 million over the 2007-2010 period to install this new equipment. SCE&G and GENCO also expect to have increased operation and maintenance costs related to this equipment of approximately $3.4 million in 2009 and $23 million in 2010 and each subsequent year thereafter. To meet compliance requirements for the years 2012 through 2016, the Company anticipates additional capital expenditures totaling approximately $480 million.

See notes to the condensed consolidated financial statements for additional information related to environmental matters (Note 5B) and regulatory matters (Note 2).

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. The table presents principal cash flows and related weighted average interest rates by expected maturity dates. Fair value represents quoted market prices.

As of June 30, 2007	Expected Maturity
						There-		Fair
Millions of dollars	2007	2008	2009	2010	2011	after	Total	Value
Long-Term Debt Issued:
Fixed Rate ($)	3.7	3.7	103.7	10.4	164.9	1,667.9	1,954.3	2,001.2
Average Interest Rate (%)	7.78	7.78	6.18	6.31	6.71	5.83	5.93	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
Futures Contracts - Long	2007	2008	2009
Settlement Price (a)	7.52	8.63	9.51
Contract Amount (b)	6.5	14.7	3.5
Fair Value (b)	5.9	14.5	3.3

	Expected Maturity
Commodity Swaps	2007	2008	2009
Pay fixed/receive variable (b)	32.6	64.1	4.6
Average pay rate (a)	8.7730	8.7904	10.0009
Average received rate (a)	7.7880	8.5623	9.5130
Fair value (b)	29.0	62.4	4.4

^(a) Weighted average, in dollars

^(b) Millions of dollars

As of June 30, 2007, South Carolina Electric & Gas Company (SCE&G) conducted an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of (a) the effectiveness of the design and operation of its disclosure controls and procedures and (b) any change in its internal control over financial reporting. Based on this evaluation, the CEO and CFO concluded that, as of June 30, 2007, SCE&G’s disclosure controls and procedures were effective. There has been no change in SCE&G’s internal control over financial reporting during the quarter ended June 30, 2007 that has materially affected or is reasonably likely to materially affect SCE&G’s  internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

SCANA Corporation:

The following table provides information about purchases by or on behalf of SCANA Corporation (SCANA) or any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934, as amended (Exchange Act)) of shares or other units of any class of SCANA's equity securities that are registered pursuant to Section 12 of the Exchange Act:

Issuer Purchases of Equity Securities
				(d)
				Maximum number
			(c)	(or approximate
			Total number of	dollar value) of
	(a)		shares (or units)	shares (or units)
	Total number of	(b)	purchased as part of	that may yet be
	shares (or units)	Average price paid	publicly announced	purchased under the
Period	purchased	per share (or unit)	plans or programs	plan or program
April 1-30	307,251	$44.17	307,251
May 1-31	116,055	43.92	116,055
June 1-30	82,458	41.33	82,458
Total	505,764		505,764	*

*On May 16, 2006 SCANA announced a program to convert from original issue to open market purchase of SCANA common stock for all applicable compensation and dividend reinvestment plans.  This program has no stated maximum number of  shares that may be purchased and no stated expiration date.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS (not applicable for South

                 Carolina Electric & Gas Company).

The Annual Meeting of Shareholders of SCANA Corporation Common Stock (No Par Value) was held on April 26, 2007.  The following matters were voted upon at the meeting.

1.          To elect three (3) Class II Directors for the terms specified in the Proxy Statement.

Nominee	Number of Shares Voting For	Number of Shares Voting to Withhold Authority	Total Shares Voted
W. Hayne Hipp	97,883,829	1,385,437	99,269,266
Harold C. Stowe	97,913,048	1,356,218	99,269,266
G. Smedes York	97,918,853	1,350,413	99,269,266

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

	Number of Shares
FOR	98,444,282
AGAINST	419,587
ABSTAIN	405,397
TOTAL	99,269,266

ITEM 6.  EXHIBITS

SCANA Corporation (SCANA) and South Carolina Electric & Gas Company (SCE&G):

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, and of SCE&G, for itself and its consolidated affiliates, have been omitted and SCANA and SCE&G agree to furnish a copy of such instruments to the Commission upon request.

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

(Registrants)

By:	/s/James E. Swan, IV
August 3, 2007	James E. Swan, IV
	Controller
	(Principal accounting officer)

	Applicable to Form 10-Q of
Exhibit No.	SCANA	SCE&G	Description
3.01	X		Restated Articles of Incorporation of SCANA Corporation as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference herein)
3.02	X		Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. 33-62421 and incorporated by reference herein)
3.03		X	Restated Articles of Incorporation of South Carolina Electric & Gas Company, as adopted on May 3, 2001 (Filed as Exhibit 3.01 to Registration Statement No. 333-65460 and incorporated by reference herein)
3.04		X	Articles of Amendment effective as of the dates indicated below and filed as exhibits to the Registration Statements or Exchange Act reports set forth below and are incorporated by reference herein
			May 22, 2001	Exhibit 3.02	to Registration No. 333-65460
			June 14, 2001	Exhibit 3.04	to Registration No. 333-65460
			August 30, 2001	Exhibit 3.05	to Registration No. 333-101449
			March 13, 2002	Exhibit 3.06	to Registration No. 333-101449
			May 9, 2002	Exhibit 3.07	to Registration No. 333-101449
			June 4, 2002	Exhibit 3.08	to Registration No. 333-101449
			August 12, 2002	Exhibit 3.09	to Registration No. 333-101449
			March 13, 2003	Exhibit 3.03	to Registration No. 333-108760
			May 22, 2003	Exhibit 3.04	to Registration No. 333-108760
			June 18, 2003	Exhibit 3.05	to Registration No. 333-108760
			August 7, 2003	Exhibit 3.06	to Registration No. 333-108760
			February 26, 2004	Exhibit 3.05	to Form 10-K for the year ended December 31, 2004
			May 18, 2004	Exhibit 3.05	to Form 10-Q for the quarter ended June 30, 2004
			June 18, 2004	Exhibit 3.06	to Form 10-Q for the quarter ended June 30, 2004
			August 12, 2004	Exhibit 3.05	to Form 10-Q for the quarter ended Sept. 30, 2004
			March 9, 2005	Exhibit 3.11	to Form 10-Q for the quarter ended Sept. 30, 2005
			May 16, 2005	Exhibit 3.12	to Form 10-Q for the quarter ended Sept. 30, 2005
			June 15, 2005	Exhibit 3.13	to Form 10-Q for the quarter ended Sept. 30, 2005
			August 16, 2005	Exhibit 3.14	to Form 10-Q for the quarter ended Sept. 30, 2005
			March 14, 2006	Exhibit 3.01	to Form 8-K dated March 17, 2006
			May 11, 2006	Exhibit 3.01	to Form 8-K filed May 15, 2006
			June 28, 2006	Exhibit 3.01	to Form 8-K filed June 29, 2006
			August 16, 2006	Exhibit 3.01	to Form 8-K filed August 17, 2006
			March 13, 2007	Exhibit 3.01	to Form 8-K filed March 15, 2007
			May 22, 2007	Exhibit 3.01	to Form 8-K filed May 23, 2007
			June 22, 2007	Exhibit 3.01	to Form 8-K filed June 26, 2007
3.05		X	Articles of Correction filed on June 1, 2001 correcting May 22, 2001 Articles of Amendment (Filed as Exhibit 3.03 to Registration Statement No. 333-65460 and incorporated by reference herein)
3.06		X	Articles of Correction filed on February 17, 2004 correcting Articles of Amendment for the dates indicated below and filed as exhibits to the 2003 Form 10-K as set forth below and are incorporated by reference herein
			May 3, 2001	Exhibit 3.06
			May 22, 2001	Exhibit 3.07
			June 14, 2001	Exhibit 3.08
			August 30, 2001	Exhibit 3.09
			March 13, 2002	Exhibit 3.10
			May 9, 2002	Exhibit 3.11
			June 4, 2002	Exhibit 3.12
			August 12, 2002	Exhibit 3.13

	Applicable to Form 10-Q of
Exhibit No.	SCANA	SCE&G	Description
			March 13, 2003	Exhibit 3.14
			May 22, 2003	Exhibit 3.15
			June 18, 2003	Exhibit 3.16
			August 7, 2003	Exhibit 3.17
3.07		X	Articles of Correction dated March 17, 2006, correcting March 14, 2006 Articles of Amendment (Filed as Exhibit 3.02 to Form  8-K dated March 17, 2006 and incorporated by reference herein)
3.08		X	Articles of Correction dated September 6, 2006, correcting August 16, 2006 Articles of Amendment (Filed as Exhibit 3.01 to Form 8-K filed September 7, 2006 and incorporated by reference herein)
3.09	X		By-Laws of SCANA as revised and amended on December 13, 2000 (Filed as Exhibit 3.01 to Registration Statement No. 333-68266 and incorporated by reference herein)
3.10		X	By-Laws of SCE&G as revised and amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460 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)
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)