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, 2010

OR

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

For the Transition Period from            to           

Commission	Registrant, State of Incorporation,	I.R.S. Employer
File Number	Address and Telephone Number	Identification No.
1-8809	SCANA Corporation	57-0784499
	(a South Carolina corporation)
	100 SCANA Parkway, Cayce, South Carolina 29033
	(803) 217-9000
1-3375	South Carolina Electric & Gas Company	57-0248695
	(a South Carolina corporation)
	100 SCANA Parkway, Cayce, South Carolina 29033
	(803) 217-9000

Indicate by check mark whether the registrant: (1) has 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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

SCANA Corporation Yes x No o  South Carolina Electric & Gas Company Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

SCANA Corporation Yes x No oSouth Carolina Electric & Gas Company Yes o No o

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

SCANA Corporation	Large accelerated filer  x	Accelerated filer  o	Non-accelerated filer  o
	Smaller reporting company  o
South Carolina Electric & Gas Company	Large accelerated filer  o	Accelerated filer  o	Non-accelerated filer  x
	Smaller reporting company  o

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

SCANA Corporation Yes o No x  South Carolina Electric & Gas Company Yes o No x

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

	Description of	Shares Outstanding
Registrant	Common Stock	at July 31, 2010
SCANA Corporation	Without Par Value		126,620,683
South Carolina Electric & Gas Company	Without Par Value		40,296,147	(a)

(a) Held 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.

South Carolina Electric & Gas Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and therefore is filing this Form with the reduced disclosure format allowed under General Instruction H(2).

TABLE OF CONTENTS

JUNE 30, 2010

			Page
Cautionary Statement Regarding Forward-Looking Information			3
Definitions			4
PART I. FINANCIAL INFORMATION
SCANA Corporation Financial Section			5
	Item 1.	Financial Statements	6
		Condensed Consolidated Balance Sheets	6
		Condensed Consolidated Statements of Income	8
		Condensed Consolidated Statements of Cash Flows	9
		Condensed Consolidated Statements of Comprehensive Income	10
		Notes to Condensed Consolidated Financial Statements	11
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
	Item 4.	Controls and Procedures	33
South Carolina Electric & Gas Company Financial Section			34
	Item 1.	Financial Statements	35
		Condensed Consolidated Balance Sheets	35
		Condensed Consolidated Statements of Income	37
		Condensed Consolidated Statements of Cash Flows	38
		Condensed Consolidated Statements of Comprehensive Income	39
		Notes to Condensed Consolidated Financial Statements	40
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	52
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	58
	Item 4.	Controls and Procedures	59
PART II. OTHER INFORMATION			60
	Item 6.	Exhibits	60
Signatures			61
Exhibit Index			62

2

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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 and estimated construction and other expenditures.  In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “forecasts,” “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, regulations governing electric grid reliability, and environmental regulations;
(3)	current and future litigation;
(4)	changes in the economy, especially in areas served by subsidiaries of SCANA;
(5)	the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets;
(6)	growth opportunities for SCANA’s regulated and diversified subsidiaries;
(7)	the results of short- and long-term financing efforts, including future prospects for obtaining access to capital markets and other sources of liquidity;
(8)	changes in SCANA’s or its subsidiaries’ accounting rules and accounting policies;
(9)	the effects of weather, including drought, especially in areas where the generation and transmission facilities of SCANA and its subsidiaries (the Company) are located and in areas served by SCANA’s subsidiaries;
(10)	payment by counterparties as and when due;
(11)	the results of efforts to license, site, construct and finance facilities for baseload electric generation;
(12)	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;
(13)	the availability of skilled and experienced human resources to properly manage, operate, and grow the Company’s businesses;
(14)	labor disputes;
(15)	performance of SCANA’s pension plan assets;
(16)	higher taxes;
(17)	inflation;
(18)	compliance with regulations; and
(19)	the other risks and uncertainties described from time to time in the periodic reports filed by SCANA or SCE&G with the SEC.

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

3

DEFINITIONS

The following abbreviations used in the text have the meanings set forth below unless the context requires otherwise:

TERM	MEANING
AER	Alternate Energy Resources, Inc.
AFC	Allowance for Funds Used During Construction
ARO	Asset Retirement Obligation
BLRA	Base Load Review Act
CAA	Clean Air Act, as amended
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CCR	Coal Combustion Residuals
CEO	Chief Executive Officer
CFO	Chief Financial Officer
CGT	Carolina Gas Transmission Corporation
Company	SCANA, together with its consolidated subsidiaries
Consolidated SCE&G	SCE&G and its consolidated affiliates
CUT	Customer Usage Tracker
CWA	Clean Water Act, as amended
DHEC	South Carolina Department of Health and Environmental Control
DSM Programs	Demand reduction and energy efficiency programs
DT	Dekatherms
Energy Marketing	The divisions of SEMI, excluding SCANA Energy
EPA	United States Environmental Protection Agency
FERC	United States Federal Energy Regulatory Commission
Fuel Company	South Carolina Fuel Company, Inc.
GENCO	South Carolina Generating Company, Inc.
GHG	Greenhouse Gas
GPSC	Georgia Public Service Commission
kW or kWh	Kilowatt or kilowatt-hour
LOC	Lines of credit
MGP	Manufactured Gas Plant
NCUC	North Carolina Utilities Commission
NYMEX	New York Mercantile Exchange
OATT	Open Access Transmission Tariff
ORS	South Carolina Office of Regulatory Staff
PGA	Purchased Gas Adjustment
PRP	Potentially Responsible Party
PSNC Energy	Public Service Company of North Carolina, Incorporated
RCRA	Resource Conservation and Recovery Act
RSA	Natural Gas Rate Stabilization Act
Santee Cooper	South Carolina Public Service Authority
SCANA	SCANA Corporation, the parent company
SCANA Energy	A division of SEMI which markets natural gas in Georgia
SCE&G	South Carolina Electric & Gas Company
SCI	SCANA Communications, Inc.
SCPSC	Public Service Commission of South Carolina
SCR	Selective Catalytic Reactor
SEC	United States Securities and Exchange Commission
SEMI	SCANA Energy Marketing, Inc.
Summer Station	V. C. Summer Nuclear Station

4

SCANA CORPORATION

FINANCIAL SECTION

5

PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

SCANA CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,			December 31,
Millions of dollars	2010			2009
Assets
Utility Plant In Service	$	11,271		$	10,835
Accumulated Depreciation and Amortization	(3,399		)	(3,302		)
Construction Work in Progress	1,096			1,149
Nuclear Fuel, Net of Accumulated Amortization	79			97
Goodwill, net of accumulated amortization and writedown of $276	230			230
Utility Plant, Net	9,277			9,009
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $109 and $107	294			291
Assets held in trust, net-nuclear decommissioning	70			67
Other investments	77			73
Nonutility Property and Investments, Net	441			431
Current Assets:
Cash and cash equivalents	82			162
Receivables, net of allowance for uncollectible accounts of $10 and $9	594			694
Inventories (at average cost):
Fuel and gas supply	318			376
Materials and supplies	123			115
Emission allowances	8			10
Prepayments and other	193			164
Total Current Assets	1,318			1,521
Deferred Debits and Other Assets:
Regulatory assets	1,073			985
Other	143			148
Total Deferred Debits and Other Assets	1,216			1,133
Total	$	12,252		$	12,094

6

	June 30,		December 31,
Millions of dollars	2010		2009
Capitalization and Liabilities
Common Equity	$	3,544	$	3,408
Long-Term Debt, net	4,021		4,483
Total Capitalization	7,565		7,891
Current Liabilities:
Short-term borrowings	231		335
Current portion of long-term debt	629		28
Accounts payable	311		428
Customer deposits and customer prepayments	91		103
Taxes accrued	-		134
Interest accrued	72		71
Dividends declared	61		59
Other	209		98
Total Current Liabilities	1,604		1,256
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,222		1,122
Deferred investment tax credits	69		111
Asset retirement obligations	490		477
Pension and other postretirement benefits	233		229
Regulatory liabilities	900		879
Other	169		129
Total Deferred Credits and Other Liabilities	3,083		2,947
Commitments and Contingencies (Note 7)	-		-
Total	$	12,252	$	12,094

See Notes to Condensed Consolidated Financial Statements.

7

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
Millions of dollars, except per share amounts	2010			2009			2010			2009
Operating Revenues:
Electric	$	575		$	521		$	1,115		$	1,018
Gas - regulated	137			136			567			558
Gas - nonregulated	227			221			685			645
Total Operating Revenues	939			878			2,367			2,221
Operating Expenses:
Fuel used in electric generation	222			190			456			375
Purchased power	3			3			5			8
Gas purchased for resale	277			269			936			913
Other operation and maintenance	167			163			339			322
Depreciation and amortization	83			83			166			165
Other taxes	50			45			98			90
Total Operating Expenses	802			753			2,000			1,873
Operating Income	137			125			367			348
Other Income (Expense):
Other income	13			12			26			24
Other expenses	(9		)	(12		)	(19		)	(20		)
Interest charges, net of allowance for borrowed funds used during construction of $3, $6, $5 and $12	(66		)	(55		)	(131		)	(113		)
Allowance for equity funds used during construction	7			7			10			14
Total Other Expense	(55		)	(48		)	(114		)	(95		)
Income Before Income Tax Expense and Earnings from Equity Method Investments	82			77			253			253
Income Tax Expense	29			21			74			82
Income Before Earnings from Equity Method Investments	53			56			179			171
Earnings from Equity Method Investments	1			1			1			2
Net Income	54			57			180			173
Less Preferred Stock Dividends of Subsidiary	-			(2		)	-			(4		)
Income Available to Common Shareholders of SCANA	$	54		$	55		$	180		$	169
Basic and Diluted Earnings Per Share of Common Stock	$	.43		$	.45		$	1.45		$	1.39
Weighted Average Common Shares Outstanding (millions)	125.2			121.8			124.5			121.4
Dividends Declared Per Share of Common Stock	$	.475		$	.47		$	.95		$	.94

See Notes to Condensed Consolidated Financial Statements.

8

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
Millions of dollars	2010			2009
Cash Flows From Operating Activities:
Net income	$	180		$	173
Adjustments to reconcile net income to net cash provided from operating activities:
Earnings from equity method investments, net of distributions	(1		)	(1		)
Deferred income taxes, net	116			37
Depreciation and amortization	174			179
Amortization of nuclear fuel	18			11
Allowance for equity funds used during construction	(10		)	(14		)
Carrying cost recovery	(3		)	(3		)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	100			279
Inventories	30			27
Prepayments and other	(19		)	60
Regulatory liabilities	(3		)	18
Accounts payable	(53		)	(105		)
Taxes accrued	(134		)	(56		)
Interest accrued	1			-
Regulatory assets	(90		)	(111		)
Changes in other assets	(8		)	(20		)
Changes in other liabilities	62			(74		)
Net Cash Provided From Operating Activities	360			400
Cash Flows From Investing Activities:
Utility property additions and construction expenditures	(432		)	(400		)
Proceeds from investments and sale of assets	8			15
Nonutility property additions	(15		)	(57		)
Purchase of investments	(22		)	-
Net Cash Used For Investing Activities	(461		)	(442		)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock	106			147
Proceeds from issuance of long-term debt	203			208
Repayment of long-term debt	(67		)	(137		)
Dividends	(117		)	(114		)
Short-term borrowings, net	(104		)	56
Net Cash Provided From Financing Activities	21			160
Net Increase (Decrease) In Cash and Cash Equivalents	(80		)	118
Cash and Cash Equivalents, January 1	162			272
Cash and Cash Equivalents, June 30	$	82		$	390
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $5 and $12)	$	132		$	113
- Income taxes	55			53
Noncash Investing and Financing Activities:
Accrued construction expenditures	95			119
Capital lease of gas utility plant	6			-

See Notes to Condensed Consolidated Financial Statements.

9

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Millions of dollars	2010			2009			2010			2009
Net Income	$	54		$	57		$	180		$	173
Other Comprehensive Income (Loss), net of tax:
Unrealized holding gains (losses) arising during period, net	(29		)	4			(40		)	(19		)
Reclassified to net income:
Losses on cash flow hedging activities	4			16			9			43
Amortization of deferred employee benefit plan costs, net of taxes	-			1			1			2
Total Comprehensive Income	29			78			150			199
Less Comprehensive income attributable to noncontrolling interest	-			(2		)	-			(4		)
Comprehensive income attributable to SCANA Corporation (1)	$	29		$	76		$	150		$	195

(1)  Accumulated other comprehensive loss totaled $84.7 million as of June 30, 2010 and $54.9 million as of December 31, 2009.

See Notes to Condensed Consolidated Financial Statements.

10

SCANA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in SCANA’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2009. 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’s cost-based, rate-regulated utilities 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 regulatory assets and liabilities which are summarized in the following tables.  Substantially all of our regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.

	June 30,		December 31,
Millions of dollars	2010		2009
Regulatory Assets:
Accumulated deferred income taxes	$	173	$	173
Under-collections - electric fuel adjustment clause	62		55
Environmental remediation costs	32		26
Asset retirement obligations and related funding	290		279
Franchise agreements	47		50
Deferred employee benefit plan costs	326		325
Planned major maintenance	4		5
Deferred losses on interest rate derivatives	108		50
Other	31		22
Total Regulatory Assets	$	1,073	$	985
Regulatory Liabilities:
Accumulated deferred income taxes	$	28	$	30
Other asset removal costs	757		733
Storm damage reserve	46		44
Monetization of bankruptcy claim	39		40
Deferred gains on interest rate derivatives	28		29
Other	2		3
Total Regulatory Liabilities	$	900	$	879

Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset.  Substantially all of these regulatory assets are expected to be recovered over the remaining lives of the related property which may range up to approximately 70 years.  Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.

Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC during annual hearings which are expected to be recovered in retail electric rates in future periods.  These amounts are expected to be recovered in retail electric rates during the period May 2011 through April 2012.  SCE&G is allowed to recover interest on actual base fuel deferred balances through the recovery period.

11

Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by the Company.  These regulatory assets are expected to be recovered over periods of up to approximately 23 years.

ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs.  These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 95 years.

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.

Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders.  A significant majority of these deferred costs are expected to be recovered through utility rates over average service periods of participating employees, or up to approximately 14 years.

Planned major maintenance related to certain fossil hydro turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved through specific SCPSC orders.  SCE&G is presently collecting and will continue to collect $8.5 million annually through July 15, 2010, through electric rates to offset turbine maintenance expenditures. After July 15, 2010, SCE&G will collect $18.4 million annually for this purpose.  Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.

Deferred losses or gains on interest rate derivatives represent the effective portions of changes in fair value and payments made or received upon termination of certain interest rate swaps, treasury rate locks and forward starting swap agreements designated as cash flow hedges.  These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years.

Various other regulatory assets are expected to be recovered in rates over periods of up to 30 years.

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

The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year, certain transmission and distribution insurance premiums and certain tree trimming and vegetation management expenditures in excess of amounts included in base rates.  During the six months ended June 30, 2010 and 2009, SCE&G applied costs of $1.5 million and $1.4 million, respectively, to the reserve.  Pursuant to SCPSC’s July 2010 order approving an electric rate increase, SCE&G suspended collection of storm damage reserve funds indefinitely pending future SCPSC action and, effective January 2011, SCE&G will no longer apply tree trimming and vegetation management expenditures against the reserve.

The monetization of bankruptcy claim represents proceeds from the sale of a bankruptcy claim which will be amortized into operating revenue through the year 2024.

The SCPSC or the NCUC (collectively, state public service commissions) or the FERC have reviewed and approved through specific orders most of the items shown as regulatory assets.  Other regulatory assets include certain costs which have not been approved for recovery by a state public service commission or by the FERC.  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.  In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, the Company 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.

12

B.Earnings Per Share

The Company computes basic earnings per share by dividing income available to common shareholders 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.Pension and Other Postretirement Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2010			2009			2010		2009
Three months ended June 30,
Service cost	$	4.8		$	3.8		$	1.1	$	1.1
Interest cost	11.9			11.2			3.2		3.1
Expected return on assets	(16.5		)	(12.9		)	-		-
Prior service cost amortization	1.8			1.8			0.2		0.3
Transition obligation amortization	-			-			0.1		0.2
Amortization of actuarial loss	4.3			5.8			0.1		-
Net periodic benefit cost	$	6.3		$	9.7		$	4.7	$	4.7
Six months ended June 30,
Service cost	$	9.5		$	7.6		$	2.2	$	2.2
Interest cost	23.7			22.5			6.2		6.1
Expected return on assets	(32.9		)	(25.7		)	-		-
Prior service cost amortization	3.7			3.5			0.5		0.6
Transition obligation amortization	-			-			0.3		0.4
Amortization of actuarial loss	8.6			11.5			0.2		-
Net periodic benefit cost	$	12.6		$	19.4		$	9.4	$	9.3

Through July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension expense above that which is included in current rates for SCE&G’s retail electric and gas distribution regulated operations.  In connection with the SCPSC’s July 2010 electric rate order, SCE&G began deferring all pension expense or income related to retail electric operations as a regulatory asset or liability, as applicable.  Costs totaling $5.3 million and $10.7 million were deferred for the three and six months ended June 30, 2010, respectively.  Costs totaling $7.8 million and $15.6 million were deferred for the corresponding periods in 2009.

D.New Accounting Matters

Effective January 1, 2010, the Company adopted accounting guidance that requires additional disclosures for assets and liabilities recorded at fair value.  This guidance requires disclosure of fair value for each class of assets and liabilities.  In addition, when the basis for measuring the fair value of a previously recorded asset or liability changes, this guidance requires disclosure of values transferred between Levels 1 and 2 of the fair value hierarchy, if significant.  The initial adoption of this guidance did not impact the Company’s results of operations, cash flows or financial position.

E.Income Taxes

In the first quarter of 2010, in connection with a fuel cost recovery settlement (see Note 2), SCE&G accelerated the recognition of certain previously deferred state income tax credits.  In the second quarter of 2010, the Company revised (reduced) its estimate of the benefit to be realized from the domestic production activities deduction as a result of a change in method of accounting for certain repairs for tax purposes.

No material changes in the status of the Company’s tax positions have occurred through June 30, 2010.

13

F.Asset Management and Supply Service Agreements

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities.  At June 30, 2010, such counterparties held 46% of PSNC Energy’s natural gas inventory, with a carrying value of $18 million, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees.  No fees are received under supply service agreements.  The agreements expire at various times through March 31, 2011.

2.REGULATORY MATTERS

SCE&G

Electric

SCE&G’s electric rates are established using a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G.  Effective with the first billing cycle of May 2010, the SCPSC approved a settlement agreement authorizing SCE&G to decrease the fuel cost portion of its electric rates.  The settlement agreement incorporated SCE&G’s proposal to accelerate the recognition of $17.4 million of previously deferred state income tax credits and record an offsetting reduction to the recovery of fuel costs.  In addition, SCE&G agreed to defer recovery of its actual undercollected base fuel costs as of April 30, 2010 for the period of May 1, 2010 through April 30, 2011.  SCE&G is allowed to charge and recover carrying costs monthly on the actual base fuel costs undercollected balance as of the end of each month during this deferral period.

On July 15, 2010, the SCPSC issued an order approving a 4.88% overall increase in SCE&G’s retail electric base rates and authorized an allowed return on common equity of 10.7%.  The SCPSC’s order adopted various stipulations among SCE&G, the ORS and other intervening parties.  Among other things, the SCPSC’s order included implementation of a pilot weather normalization mechanism for SCE&G’s electric customers, which will begin in August 2010, provided for a $25 million credit to SCE&G’s customers based on first quarter 2010 weather-related revenues, provided for a $48.7 million credit to SCE&G’s customers over two years for previously deferred state income tax credits and provided for the recovery of certain federally-mandated capital expenditures that had been included in utility plant but were not being depreciated.

On July 15, 2010, the SCPSC issued an order approving the implementation by SCE&G of certain DSM Programs, including the establishment of an annual rider to allow recovery of the costs and lost net margin revenue associated with DSM Programs, along with an incentive for investing in such programs.  The SCPSC’s order approved various settlement agreements among SCE&G, the ORS and other intervening parties.

In December 2009, SCE&G submitted to the FERC revised tariff sheets to change the network and point to point transmission rates under SCE&G’s OATT.  The request, if approved, would result in an annual revenue increase of $5.6 million.  On March 1, 2010 pursuant to an order issued by the FERC, SCE&G implemented, subject to refund, the proposed tariff sheets.  In compliance with the OATT, on May 17, 2010, SCE&G submitted to the FERC as an informational filing its recalculated Annual Transmission Revenue Requirement or “Annual Update” for the period June 1, 2010 through May 31, 2011.  The FERC accepted the tariff sheets in the “Annual Update” and made them effective subject to refund as of June 1, 2010.

Electric – BLRA

In January 2010, the SCPSC approved SCE&G’s request for an order pursuant to the BLRA to approve an updated construction and capital cost schedule for the construction of two new nuclear generating units at Summer Station.  The updated schedule provides details of the construction and capital cost schedule beyond what was proposed and included in the original BLRA filing described below.  The revised schedule does not change the previously announced completion date for the new units or the originally announced cost.

In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the BLRA seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to the proposed construction and operation by SCE&G and Santee Cooper of two new nuclear generating units at Summer Station.  Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built.  The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, including contingencies, as approved by the SCPSC.  As part of its order, the SCPSC approved the initial rate increase of $7.8 million, or

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0.4%, related to recovery of the cost of capital on project expenditures through June 30, 2008, and the revised rates became effective for bills rendered on and after March 29, 2009.  In May 2009, two intervenors filed separate appeals of the order (one of which challenged the SCPSC’s prudency finding) with the South Carolina Supreme Court.  With regard to the first appeal, which challenged the SCPSC’s prudency finding, the South Carolina Supreme Court issued an opinion on April 26, 2010, affirming the decision of the SCPSC.  As for the second appeal, the South Carolina Supreme Court heard oral arguments on April 6, 2010.  SCE&G cannot predict how or when the Court will rule.

Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation.  Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%.  In September 2009, the SCPSC approved SCE&G’s annual revised rate request under the BLRA which constituted a $22.5 million or 1.1% increase to retail electric rates.  On May 28, 2010, SCE&G filed with the SCPSC for its annual revised rate request under the BLRA.  If approved, SCE&G expects this request will constitute a $47.0 million, or 2.3%, increase to retail electric rates.

Gas

SCE&G

The RSA 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 infrastructure.  On June 15, 2010, pursuant to the annual RSA filing, SCE&G requested a decrease in retail natural gas rates of $10.1 million.  If approved by the SCPSC, the rate adjustment will be effective with the first billing cycle of November 2010.  In October 2009, the SCPSC approved an increase in SCE&G’s retail natural gas base rates of $13.0 million under the terms of the RSA.  The rate adjustment was effective with the first billing cycle of November 2009.

SCE&G’s tariffs include a PGA clause that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities.  SCE&G’s rates are calculated using a methodology which adjusts the cost of gas monthly based on a 12-month rolling average.  In December 2009, in connection with the annual review of the PGA and the gas purchasing policies of SCE&G, the SCPSC determined that SCE&G’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 17 months ended July 31, 2009.  The SCPSC has scheduled a public hearing for November 10, 2010 to conduct its annual review of the PGA and gas purchasing policies of SCE&G for the 12 months ended July 31, 2010.

PSNC Energy

PSNC Energy’s rates are established using a benchmark cost of gas approved by the NCUC, which may be modified periodically to reflect changes in the market price of natural gas.  PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and defers any over- or under-collections of the delivered cost of gas for subsequent rate consideration.  The NCUC reviews PSNC Energy’s gas purchasing practices annually.  In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates for residential and commercial customers based on average per customer consumption.

In February 2010, the NCUC approved a ten cent per therm increase in the cost of gas component of PSNC Energy’s rates.  The rate adjustment was effective with the first billing cycle in March 2010.

3.LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In March 2010, PSNC Energy issued $100 million of 6.54% unsecured notes due March 30, 2020.   Proceeds from these notes were used to pay down short-term debt and for general corporate purposes.

Substantially all of SCE&G’s and GENCO’s electric utility plant is pledged as collateral in connection with long-term debt. The Company is in compliance with all debt covenants.

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Liquidity

SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:

	SCANA				SCE&G (b)						PSNC Energy (b)
	June 30,		December 31,		June 30,			December 31,			June 30,		December 31,
Millions of dollars	2010		2009		2010			2009			2010		2009
Lines of credit:
Committed long-term (expire December 2011) (a)
Total	$	200	$	200	$	650		$	650		$	250	$	250
LOC advances	-		-		150			100			-		-
Weighted average interest rate	-		-		.62		%	.50		%	-		-
Outstanding commercial paper (270 or fewer days)	-		-		231			254			-		81
Weighted average interest rate	-		-		.45		%	.33		%	-		.32		%
Letters of credit supported by LOC	3		3		.3			.3			-		-
Available	197		197		269			296			250		169

(a)The Company’s committed long-term facilities serve to backup the issuance of commercial paper or to provide liquidity support.

(b)SCE&G, Fuel Company and PSNC Energy may issue commercial paper in the amounts of up to $350 million, $250 million and $250 million, respectively. Nuclear and fossil fuel inventories and emission allowances are financed through the issuance by Fuel Company of short-term commercial paper or LOC advances.

The committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks.  Wells Fargo Bank, N. A. provides 18.9% of the aggregate $1.1 billion credit facilities, Bank of America, N. A. provides 14.3%, Branch Banking and Trust Company, UBS Loan Finance LLC, Morgan Stanley Bank, and Credit Suisse, each provide 10.9%, and The Bank of New York and Mizuho Corporate Bank, Ltd each provide 9.1%.  Three other banks provide the remaining 5.0%.  These bank credit facilities support the issuance of commercial paper by SCE&G (including Fuel Company) and PSNC Energy.  In addition, a portion of the credit facilities supports SCANA’s borrowing needs.  When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCE&G (including Fuel Company) and PSNC Energy.

4.COMMON EQUITY

SCANA issued common stock valued at $48.8 million (at time of issue) during the six months ended June 30, 2010 through various compensation and dividend reinvestment plans, including the exercise of 9,091 stock options during the period.  In addition, SCANA issued common stock valued at $59.2 million (at time of issue) in a public offering on May 17, 2010, and entered into forward sale contracts for approximately 6.6 million common shares to be sold over the next 22 months.

5.DERIVATIVE FINANCIAL INSTRUMENTS

The Company recognizes all derivative instruments as either assets or liabilities in the statement of financial position and measures those instruments at fair value.  The Company recognizes changes in the fair value of derivative instruments either in earnings, as a component of other comprehensive income (loss) or, for regulated subsidiaries, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation.  The fair value of derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or, for interest rate swaps, discounted cash flow models with independently sourced data.

Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by the Company.  SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries.  The Risk Management Committee, which is comprised of certain officers, including the Company’s Risk Management Officer and senior officers, apprises the Board of Directors with regard to the management of risk and brings to the Board’s attention any areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

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Commodity Derivatives

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations.  Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas.  The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy and financial institutions.

The Company’s regulated gas operations (SCE&G and PSNC Energy) hedge natural gas purchasing activities using over-the-counter options and swaps and NYMEX futures and options.  SCE&G’s tariffs include a PGA that provides for the recovery of actual gas costs incurred.  The SCPSC has ruled that the results of SCE&G’s hedging activities are to be included in the PGA.  As such, the cost of derivatives and gains and losses on such 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 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.  These derivative financial instruments are not designated as hedges for accounting purposes.

The unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in other comprehensive income.  When the hedged transactions affect earnings, the previously deferred gains and losses are reclassified from other comprehensive income to 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.

As an accommodation to certain customers, SEMI, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives.  These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives.

Interest Rate Swaps

The Company uses interest rate swaps to manage interest rate risk on certain debt issuances.  These swaps are designated as either fair value hedges or cash flow hedges.

The Company uses swaps to synthetically convert fixed rate debt to variable rate debt.  These swaps are designated as fair value hedges.  Prior to 2006, some of these swaps were terminated prior to maturity of the underlying debt instruments.  The gains on these terminated swaps are being amortized over the life of the debt they hedged.

The Company also uses swaps to synthetically convert variable rate debt to fixed rate debt.  In addition, in anticipation of the issuance of debt, the Company may use treasury rate lock or forward starting swap agreements which are designated as cash flow hedges.  The effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities, and for the holding company or nonregulated subsidiaries, are recorded in other comprehensive income.  Ineffective portions of changes in fair value are recognized in income.

The effective portions of settlement payments made or received upon termination are amortized to interest expense over the term of the underlying debt and are classified as a financing activity in the condensed consolidated statements of cash flows.

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Quantitative Disclosures Related to Derivatives

The Company was party to natural gas derivative contracts outstanding in the following quantities:

	Commodity and Other Energy Management Contracts (in DT)
Hedge designation	Gas Distribution	Retail Gas Marketing	Energy Marketing	Total
As of June 30, 2010
Cash flow	-	4,347,800	6,170,843	10,518,643
Not designated (a)	10,603,000	-	26,491,557	37,094,557
Total (a)	10,603,000	4,347,800	32,662,400	47,613,200
As of December 31, 2009
Cash flow	-	5,390,350	13,915,971	19,306,321
Not designated (b)	6,291,000	160,000	19,007,840	25,458,840
Total (b)	6,291,000	5,550,350	32,923,811	44,765,161

(a)  Includes an aggregate 6,405,144 DT related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 9,961,000 DT related to basis swap contracts in Retail Gas Marketing and Energy Marketing.

At June 30, 2010 and December 31, 2009, the Company was party to interest rate swaps designated as fair value hedges with an aggregate notional amount of $556.4 million and $559.6 million, respectively, and was party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $1,077.0 million and $181.4 million, respectively.

The fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheet as follows:

	Fair Values of Derivative Instruments
	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
Millions of dollars	Location (c)	Value		Location (c)	Value
As of June 30, 2010
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	1	Other current liabilities	$	70
	Other deferred debits	6		Other deferred credits	53
Commodity contracts	Other current liabilities	1		Other current liabilities	6
				Other deferred credits	3
Total		$	8		$	132
Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other	$	3
Energy management contracts	Prepayments and other	6		Prepayments and other	$	1
	Other deferred debits	2		Other current liabilities	5
				Other deferred credits	2
Total		$	11		$	8
As of December 31, 2009
Derivatives designated as hedging instruments
Interest rate contracts	Other deferred debits	$	5	Other deferred credits	$	14
Commodity contracts	Other current liabilities	1		Other current liabilities	7
				Other deferred credits	2
Total		$	6		$	23
Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other	$	1
Energy management contracts	Prepayments and other	2		Other current liabilities	$	3
	Other current liabilities	2		Other deferred credits	1
	Other deferred debits	1
Total		$	6		$	4

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(c)Asset derivatives represent unrealized gains to the Company, and liability derivatives represent unrealized losses.  In the Company’s condensed consolidated balance sheets, unrealized gain and loss positions on commodity contracts with the same counterparty are reported as either a net asset or liability.

The effect of derivative instruments on the statements of income is as follows:

Derivatives in Fair Value Hedging Relationships

With regard to the Company’s interest rate swaps designated as fair value hedges, the gains on those swaps and the losses on the hedged fixed rate debt are recognized in current earnings and included in interest expense.  These gains and losses, combined with the amortization of gains on those swaps that were terminated prior to 2006 as discussed above, resulted in reductions to interest expense of $2.0 million and $5.2 million for the three and six months ended June 30, 2010, respectively, and $1.4 million and $2.7 million for the three and six months ended June 30, 2009, respectively.

Derivatives in Cash Flow Hedging Relationships

	Gain (Loss) Deferred			Gain (Loss) Reclassified from
Derivatives in Cash Flow	in Regulatory Accounts			Deferred Accounts into Income
Hedging Relationships	(Effective Portion)			(Effective Portion)
Millions of dollars				Location	Amount
Three Months Ended June 30, 2010
Interest rate contracts	$	(63	)	Interest expense	$	-
Six Months Ended June 30, 2010
Interest rate contracts	$	(60	)	Interest expense	$	(1	)
Three Months Ended June 30, 2009
Interest rate contracts	$	27		Interest expense	$	-
Six Months Ended June 30, 2009
Interest rate contracts	$	50		Interest expense	$	(1	)

	Gain (Loss)			Gain (Loss) Reclassified from
Derivatives in Cash Flow	Recognized in OCI,			Accumulated OCI into Income,
Hedging Relationships	net of tax			net of tax (Effective Portion)
Millions of dollars	(Effective Portion)			Location	Amount
Three Months Ended June 30, 2010
Interest rate contracts	$	(31	)	Interest expense	$	(1	)
Commodity contracts	2			Gas purchased for resale	(3		)
Total	$	(29	)		$	(4	)
Six Months Ended June 30, 2010
Interest rate contracts	$	(33	)	Interest expense	$	(2	)
Commodity contracts	(7		)	Gas purchased for resale	(7		)
Total	$	(40	)		$	(9	)
Three Months Ended June 30, 2009
Interest rate contracts	$	7		Interest expense	$	(1	)
Commodity contracts	(3		)	Gas purchased for resale	(15		)
Total	$	4			$	(16	)
Six Months Ended June 30, 2009
Interest rate contracts	$	9		Interest expense	$	(1	)
Commodity contracts	(28		)	Gas purchased for resale	(42		)
Total	$	(19	)		$	(43	)

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As of June 30, 2010, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive loss to earnings arising from cash flow hedges will include approximately $3.6 million as an increase to gas cost and approximately $3.0 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of June 30, 2010, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2013.

	Gain (Loss) Recognized in Income
Derivatives not designated as
Hedging Instruments
Millions of dollars	Location	2010			2009
Second Quarter
Commodity contracts	Gas purchased for resale	$	(1	)	$	(3	)
Other energy management contracts	Gas purchased for resale	-			2
Total		$	(1	)	$	(1	)
Year to Date
Commodity contracts	Gas purchased for resale	$	(2	)	$	(6	)
Total		$	(2	)	$	(6	)

Hedge Ineffectiveness

Other losses recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were $0.2 million, net of tax, for each of the three and six months ended June 30, 2010.  Other gains recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were $1.9 million and $2.0 million, net of tax, for the three and six months ended June 30, 2009, respectively.

Credit Risk Considerations

Certain of the Company’s derivative instruments contain contingent provisions that require the Company to provide collateral upon the occurrence of specific events, primarily credit downgrades.  As of June 30, 2010, the Company has posted $36.0 million of collateral related to derivatives with contingent provisions that are in a net liability position.  If all of the contingent features underlying these instruments were fully triggered as of June 30, 2010, the Company would be required to post an additional $101.9 million of collateral to its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of June 30, 2010, is $137.9 million.

6.FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

The Company values available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, where the securities are actively traded.  For commodity derivative assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments.  The Company’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data.  Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:

		Fair Value Measurements Using
		Quoted Prices in Active	Significant Other
		Markets for Identical Assets	Observable Inputs
Millions of dollars		(Level 1)	(Level 2)
As of June 30, 2010
Assets -	Available for sale securities	$              3	$            -
	Interest rate contracts	-	7
	Commodity contracts	2	2
	Energy management contracts	-	8
Liabilities -	Interest rate contracts	-	123
	Commodity contracts	-	9
	Energy management contracts	-	10

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As of December 31, 2009
Assets -	Available for sale securities	$              2	$            -
	Interest rate contracts	-	5
	Commodity contracts	1	1
	Energy management contracts	-	5
Liabilities -	Interest rate contracts	-	14
	Commodity contracts	-	9
	Energy management contracts	-	7

There were no fair value measurements based on significant unobservable inputs (Level 3) for either period presented.  In addition, there were no transfers of fair value amounts into or out of Levels 1 and 2 during any period presented.

Financial instruments for which the carrying amount may not equal estimated fair value at June 30, 2010 and December 31, 2009 were as follows:

	June 30, 2010				December 31, 2009
Millions of dollars	CarryingAmount		EstimatedFairValue		CarryingAmount		EstimatedFairValue
Long-term debt	$	4,649.7	$	5,123.0	$	4,510.9	$	4,726.0

Fair values of long-term debt are based on quoted market prices of the instruments or similar instruments.  For debt instruments for which no quoted market prices are available, fair values are based on net present value calculations.  Carrying values reflect the fair values of interest rate swaps based on discounted cash flow models with independently sourced data.  Early settlement of long-term debt may not be possible or may not be considered prudent.  Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been considered.

7.COMMITMENTS AND CONTINGENCIES

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 $12.6 billion.  Each reactor licensee is currently liable for up to $117.5 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5 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 $78.3 million per incident, but not more than $11.7 million per year.

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station) with Nuclear Electric Insurance Limited.  The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer’s losses.  Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $14.2 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 rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer.  SCE&G has no reason to anticipate a serious nuclear incident.  However, if such an incident were to occur, it likely would have a material adverse impact on the Company’s results of operations, cash flows and financial position.

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B.Environmental

SCE&G

In December 2009 the EPA issued a final finding that atmospheric concentrations of GHG endanger public health and welfare within the meaning of Section 202(a) of the CAA.  The rule, which became effective in January 2010, enables the EPA to regulate GHG emissions under the CAA.  The EPA has committed to issue new rules regulating such emissions by November 2011.  On September 30, 2009, the EPA issued a proposed rule that would require facilities emitting over 25,000 tons of GHG a year (such as SCE&G’s and GENCO’s generating facilities) to obtain permits demonstrating that they are using the best practices and technologies to minimize GHG emissions.  The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

In 2005, the EPA issued the CAIR, which 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.  CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide.  Numerous states, environmental organizations, industry groups and individual companies challenged the rule, seeking a change in the method CAIR used to allocate sulfur dioxide emission allowances.  On December 23, 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the rule but did not vacate it.  Prior to the Court of Appeals’ decision, SCE&G and GENCO had determined that additional air quality controls would be needed to meet the CAIR requirements.  SCE&G has completed the installation of SCR technology at Cope Station for nitrogen oxide reduction, and GENCO has completed installation of a wet limestone scrubber at Williams Station for sulfur dioxide reduction.   SCE&G also installed a wet limestone scrubber at Wateree Station.  The Company expects to incur capital expenditures totaling approximately $559 million through 2010 for these projects, of which the majority has already been spent.  EPA has proposed a revised rule which is currently being evaluated by the Company.  Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

In June 2010, the EPA issued a final rule for a one-hour ambient air quality standard for sulfur dioxide emissions.  Initial evaluation of this new standard indicated that SCE&G’s McMeekin Station in Lexington County may be required to reduce its sulfur dioxide emissions to a level determined by EPA and/or DHEC.  The costs incurred to comply with this new standard are expected to be recovered through rates.

In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants.  Numerous parties challenged the rule.  On February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units.  The Company expects the EPA will issue a new rule on mercury emissions in 2011 but cannot predict what requirements it will impose.

SCE&G has been named, along with 53 others, by the EPA as a PRP at the AER Superfund site located in Augusta, Georgia.  The EPA placed the site on the National Priorities List in April 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 PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that was completed in 2010.  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 is expected to be recoverable through rates.

SCE&G maintains an environmental assessment program to identify and evaluate its current and former operations 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 cleanup costs and expects to recover them through rates.

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SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC.  SCE&G anticipates that major remediation activities at these sites will continue until 2012 and will cost an additional $10.2 million.  In addition, the National Park Service of the Department of the Interior has made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina.  SCE&G expects to recover any cost arising from the remediation of these four sites through rates.  At June 30, 2010, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.7 million.

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 $4.3 million, which reflects its estimated remaining liability at June 30, 2010.  PSNC Energy expects to recover through rates any costs allocable to PSNC Energy arising from the remediation of these sites.

C.Claims and Litigation

In May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette and Mark Rudd, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Communications, Inc. was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit.  The plaintiffs allege that SCE&G made improper use of certain electric transmission easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications.  The plaintiffs asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment, but did not assert a specific dollar amount for the claims.  SCE&G believes its actions are consistent with governing law and the applicable documents granting easements and rights-of-way.  In June 2007, the Circuit Court issued a ruling that limits the plaintiffs’ purported class to easement grantors situated in Charleston County, South Carolina.  In February 2008, the Circuit Court issued an order to conditionally certify the class, which remains limited to easements in Charleston County.  In July 2008, the plaintiffs’ motion to add SCI to the lawsuit as an additional defendant was granted.   SCE&G and SCI 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.

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.

D.Nuclear Generation

SCE&G and Santee Cooper have entered into a contractual agreement for the design and construction of two 1,117-megawatt nuclear electric generation units at the site of Summer Station.  SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the units, with SCE&G responsible for 55 percent of the cost and receiving 55 percent of the output, and Santee Cooper responsible for and receiving the remaining 45 percent.  Assuming timely receipt of federal approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, and the second in 2019.  SCE&G’s share of the estimated cash outlays (future value) totals $6.0 billion for plant costs and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC.

SCE&G’s latest Integrated Resource Plan filed with the SCPSC on February 26, 2010 continues to support SCE&G’s need for 55% of the output of the two units.  SCE&G has been advised by Santee Cooper that, in light of recent developments, it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the two units.  If Santee Cooper’s ownership interest in one or both of the units changes, SCE&G believes that one or more additional parties will be available to participate as joint owners.

SCE&G is unable to predict whether any change in Santee Cooper’s ownership interest or the addition of new joint owners will increase project costs or delay the commercial operation dates of the new units.  Any such project cost increase or delay could be material.

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8.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, income available to common shareholders is not allocated to the Electric Operations, Gas Distribution and Gas Transmission segments.  The Company uses income available to common shareholders 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 the criteria for aggregation.  All Other includes equity method investments and other nonreportable segments.

	External			Intersegment			Operating			Income Available to			Segment
Millions of dollars	Revenue			Revenue			Income			Common Shareholders			Assets
Three Months Ended June 30, 2010
Electric Operations	$	575		$	2		$	139			n/a
Gas Distribution		134			-			2			n/a
Gas Transmission		3			10			5			n/a
Retail Gas Marketing		74			-			n/a		$	(5	)
Energy Marketing		153			42			n/a			2
All Other		7			95			n/a			(6	)
Adjustments/Eliminations		(7	)		(149	)		(9	)		63
Consolidated Total	$	939		$	-		$	137		$	54
Six Months Ended June 30, 2010
Electric Operations	$	1,115		$	4		$	225			n/a		$	7,545
Gas Distribution		562			-			92			n/a			2,060
Gas Transmission		5			21			10			n/a			258
Retail Gas Marketing		336			-			n/a		$	24			157
Energy Marketing		349			89			n/a			2			116
All Other		13			181			n/a			(6	)		948
Adjustments/Eliminations		(13	)		(295	)		40			160			1,168
Consolidated Total	$	2,367		$	-		$	367		$	180		$	12,252
Three Months Ended June 30, 2009
Electric Operations	$	521		$	3		$	121			n/a
Gas Distribution		134			-			2			n/a
Gas Transmission		2			10			4			n/a
Retail Gas Marketing		80			-			n/a		$	(3	)
Energy Marketing		141			37			n/a			2
All Other		7			95			n/a			(4	)
Adjustments/Eliminations		(7	)		(145	)		(2	)		60
Consolidated Total	$	878		$	-		$	125		$	55
Six Months Ended June 30, 2009
Electric Operations	$	1,018		$	6		$	223			n/a		$	6,925
Gas Distribution		553			1			82			n/a			2,062
Gas Transmission		5			21			10			n/a			266
Retail Gas Marketing		308			-			n/a		$	19			139
Energy Marketing		337			79			n/a			2			97
All Other		13			180			n/a			(5	)		867
Adjustments/Eliminations		(13	)		(287	)		33			153			1,364
Consolidated Total	$	2,221		$	-		$	348		$	169		$	11,720

For the six months ended June 30, 2010, operating income for Electric Operations reflects a reduction in recovery of fuel of $17.4 million in connection with the settlement described in Note 2.  This reduction was fully offset by recognition of tax benefits.

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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’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2009.

RESULTS OF OPERATIONS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2010

AS COMPARED TO THE CORRESPONDING PERIODS IN 2009

Earnings Per Share

Earnings per share was as follows:

		Second Quarter				Year to Date
Millions of dollars		2010	2009			2010		2009
Earnings per share	$	.43	$	.45	$	1.45	$	1.39

Second Quarter

Earnings per share decreased by $.01 due to lower gas margin, $.05 due to higher operating expenses which are explained below, $.04 due to higher interest expense and by dilution from additional shares outstanding of $.01.  These decreases were partially offset by higher electric margin of $.11.

Year to Date

Earnings per share increased by $.18 due to higher electric margin (excluding the effect of the $17.4 million adjustment described at “Electric Operations”) and $.13 due to higher gas margin.  These increases were partially offset by dilution from additional shares outstanding of $.03, higher operating expenses of $.13 which are explained below and higher interest expense of $.06.

Dividends Declared

SCANA’s Board of Directors has declared the following dividends on common stock during 2010:

Declaration Date	Dividend Per Share	Record Date	Payment Date
February 11, 2010	$.475	March 10, 2010	April 1, 2010
May 6, 2010	.475	June 10, 2010	July 1, 2010
July 29, 2010	.475	September 10, 2010	October 1, 2010

Electric Operations

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

	Second Quarter						Year to Date
Millions of dollars		2010	% Change			2009		2010	% Change			2009
Operating revenues	$	577.0	10.2	%	$	523.8	$	1,118.7	9.3	%	$	1,023.9
Less:  Fuel used in generation	223.0		16.6	%	191.3		459.0		21.6	%	377.4
Purchased power	2.6		(16.1	)%	3.1		5.0		(36.7	)%	7.9
Margin	$	351.4	6.7	%	$	329.4	$	654.7	2.5	%	$	638.6

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MWh sales volumes related to the electric margin above, by class, were as follows:

	Second Quarter				Year to Date
Classification (in thousands)	2010	% Change		2009	2010	% Change		2009
Residential	1,981	6.3	%	1,864	4,280	12.5	%	3,803
Commercial	1,941	3.4	%	1,878	3,685	3.4	%	3,563
Industrial	1,493	14.8	%	1,301	2,846	10.9	%	2,567
Sale for resale (excluding interchange)	446	4.4	%	427	873	1.6	%	859
Other	143	2.9	%	139	273	0.7	%	271
Total territorial	6,004	7.0	%	5,609	11,957	8.1	%	11,063
Negotiated Market Sales Tariff (NMST)	22	(80.7	)%	114	28	(80.3	)%	142
Total	6,026	5.3	%	5,723	11,985	7.0	%	11,205

Second Quarter

Margin increased due to higher residential and commercial customer usage of $9.4 million, higher industrial sales of $1.2 million, customer growth of $2.0 million and an increase in base rates approved by the SCPSC under the BLRA of $5.9 million.

Territorial sales volume increased by 169 MWh due to increased average use and the effects of favorable weather and 189 MWh due to higher industrial sales volumes.

Year to Date

Margin increased due to higher residential and commercial customer usage of $34.0 million, higher industrial sales of $2.3 million, customer growth of $4.1 million and an increase in base rates approved by the SCPSC under the BLRA of $13.3 million.  Although weather was abnormally cold in the first quarter of 2010 and significantly colder than in the same period in 2009, estimated incremental revenues of $25 million associated with this weather have been deferred (for refund to customers) within other current liabilities based upon a stipulation related to SCE&G’s 2010 electric base rate case proceeding (see Note 2).  Also, margin in the first quarter of 2010 was adjusted downward by $17.4 million pursuant to an SCPSC regulatory order issued in connection with SCE&G’s annual fuel cost proceeding.  (See also discussion at “Income Taxes”).

Territorial sales volume increased by 579 MWh due to increased average use and the effects of favorable weather and 277 MWh due to higher industrial sales volumes.

Gas Distribution

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

	Second Quarter						Year to Date
Millions of dollars	2010		% Change		2009		2010		% Change		2009
Operating revenues	$	134.1	0.1	%	$	133.9	$	562.4	1.6	%	$	553.7
Less:  Gas purchased for resale	70.8		(3.0	)%	73.0		350.1		(1.6	)%	355.9
Margin	$	63.3	3.9	%	$	60.9	$	212.3	7.3	%	$	197.8

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DT sales volumes by class, including transportation gas, were as follows:

	Second Quarter				Year to Date
Classification (in thousands)	2010	% Change		2009	2010	% Change		2009
Residential	2,599	(17.4	)%	3,146	27,118	16.0	%	23,369
Commercial	4,409	(4.1	)%	4,598	16,151	5.9	%	15,254
Industrial	4,727	20.7	%	3,917	9,673	18.6	%	8,153
Transportation gas	11,976	0.5	%	11,916	23,576	7.3	%	21,980
Total	23,711	0.6	%	23,577	76,518	11.3	%	68,756

Second Quarter

Margin at SCE&G increased $2.1 million due to the SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2009.

Year to Date

Margin at SCE&G increased $3.9 million due to increased customer usage and $7.1 million due to the SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2009.  Margin at PSNC Energy increased by $2.0 million primarily due to residential customer growth and improved industrial usage.

Gas Transmission

Gas Transmission is comprised of the operations of CGT.  Gas transmission revenues and operating income (including transactions with affiliates) was as follows:

	Second Quarter						Year to Date
Millions of dollars		2010	% Change			2009		2010	% Change			2009
Transportation revenues	$	13.0	2.4	%	$	12.7	$	26.1	1.2	%	$	25.8
Operating income		4.6	4.5	%		4.4		9.5	(1.0	)%		9.6

Second Quarter

Transportation revenues and operating income increased primarily as a result of increased activity with existing customers.

Year to Date

Transportation revenues increased primarily as a result of increased activity with existing customers.  Operating income decreased primarily as a result of higher operating expenses.

Retail Gas Marketing

Retail Gas Marketing is comprised of SCANA Energy, which operates in Georgia’s natural gas market.  Retail Gas Marketing revenues and income (loss) available to common shareholders were as follows:

	Second Quarter								Year to Date
Millions of dollars		2010		% Change			2009			2010	% Change			2009
Operating revenues	$	73.9		(8.1	)%	$	80.4		$	336.0	9.0	%	$	308.2
Income (loss) available to common shareholders		(5.9	)	(96.7	)%		(3.0	)		23.8	25.9	%		18.9

Second Quarter

Operating revenues decreased as a result of lower demand due to warmer weather.  Income available to common shareholders decreased primarily as a result of lower margins, partially offset by lower bad debt expense.

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Year to Date

Operating revenues increased as a result of higher sales volume due to colder weather in the first quarter.  Income available to common shareholders increased primarily as a result of higher margins due to favorable weather, partially offset by higher bad debt expense.

Energy Marketing

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

		Second Quarter						Year to Date
Millions of dollars		2010	% Change			2009		2010	% Change			2009
Operating revenues	$	194.6	9.4	%	$	177.9	$	438.0	5.3	%	$	415.9
Income available to common shareholders		1.1	(45.0	)%		2.0		1.6	(15.8	)%		1.9

Second Quarter and Year to Date

Operating revenues increased primarily due to higher sales margin on increased demand.  Income available to common shareholders decreased primarily due to higher bad debt expense.

Other Operating Expenses

Other operating expenses were as follows:

		Second Quarter					Year to Date
Millions of dollars		2010	% Change			2009		2010	% Change			2009
Other operation and maintenance	$	166.9	2.1	%	$	163.5	$	338.9	5.3	%	$	321.9
Depreciation and amortization		83.0	0.5	%		82.6		165.8	0.3	%		165.3
Other taxes		50.2	12.1	%		44.8		97.8	8.7	%		90.0

Second Quarter

Other operation and maintenance expenses increased by $5.8 million due to higher incentive compensation and other benefits.  This increase was partially offset by $2.5 million due to lower generation, transmission and distribution expenses.  Depreciation and amortization expense increased in 2010 primarily due to net property additions, offset by the adoption of new, lower depreciation rates at SCE&G in late 2009.  Other taxes increased primarily due to higher property taxes.

Year to Date

Other operation and maintenance expenses increased by $9.7 million due to higher incentive compensation and other benefits, by $3.5 million due to higher generation, transmission and distribution expenses and by $3.7 million due to higher customer service expenses and general expenses, including bad debt expense.  Depreciation and amortization expense increased in 2010 primarily due to net property additions, offset by the adoption of new, lower depreciation rates at SCE&G in late 2009.  Other taxes increased primarily 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) increased in 2010 compared to 2009 primarily due to increased interest income.

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Pension Cost

Pension cost was recorded on the Company’s income statements and balance sheets as follows:

		Second Quarter						Year to Date
Millions of dollars		2010			2009			2010			2009
Income Statement Impact:
Reduction in employee benefit costs	$	(0.1	)	$	-		$	(0.2	)	$	(0.1	)
Other income		(0.9	)		(0.9	)		(1.8	)		(1.9	)
Balance Sheet Impact:
Increase in capital expenditures		1.6			2.2			3.2			4.5
Component of amount payable from Summer Station co-owner		0.4			0.6			0.8			1.3
Regulatory asset		5.3			7.8			10.6			15.6
Total Pension Cost	$	6.3		$	9.7		$	12.6		$	19.4

No contribution to the pension trust will be necessary in or for 2010, nor will limitations on benefit payments apply.  Through July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost above that which was included in rates for its retail electric and gas distribution regulated operations.  In connection with the SCPSC’s July 2010 electric rate order, SCE&G will defer all pension expense and income related to retail electric operations as a regulatory asset or regulatory liability, as applicable.  These costs will be deferred until such time as future rate recovery is provided for by the SCPSC.

AFC

AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized.  The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income.  AFC decreased in 2010 due primarily to the completion of certain pollution abatement projects at coal-fired plants.

Interest Expense

Interest charges increased primarily due to increased borrowings.

Income Taxes

Second Quarter

Income taxes (and the effective tax rate) were higher in the second quarter of 2010 than in the second quarter of 2009 primarily due to the Company’s revision (reduction) in its estimate of the benefit to be realized from the domestic production activities deduction as a result of a change in method of accounting for certain repairs for tax purposes.

Year to Date

Income taxes (and the effective tax rate) for the six months ended June 30, 2010 reflect the reduction of estimated benefit to be realized from the domestic production activities deduction (in the second quarter of 2010), which was more than offset by the recognition of certain previously deferred state income tax credits pursuant to the settlement of a fuel cost recovery proceeding in the first quarter of 2010 (see also the discussion at “Electric Operations”).

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, barring further impairment of the capital markets, it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future, including the cash requirements for nuclear construction and refinancing maturing long-term debt.  The Company’s ratio of earnings to fixed charges for both the six and 12 months ended June 30, 2010 was 2.83.

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Cash requirements for SCANA’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 upon 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.

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

SCE&G and GENCO have obtained FERC authority to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act).  SCE&G may issue up to $700 million of unsecured promissory notes or commercial paper with maturity of one year or less, and GENCO may issue up to $100 million of short-term indebtedness.  FERC’s approval expires in February 2012.

SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:

	SCANA				SCE&G (b)							PSNC Energy (b)
	June 30,		December 31,			June 30,			December 31,			June 30,		December 31,
Millions of dollars	2010		2009			2010			2009			2010		2009
Lines of credit:
Committed long-term (expire December 2011) (a)
Total	$	200	$	200		$	650		$	650		$	250	$	250
LOC advances		-		-			150			100			-		-
Weighted average interest rate		-		-			.62	%		.50	%		-		-
Outstanding commercial paper (270 or fewer days)		-		-			231			254			-		81
Weighted average interest rate		-		-			.45	%		.33	%		-		.32	%
Letters of credit supported by LOC		3		3			.3			.3			-		-
Available		197		197			269			296			250		169

(a)The Company’s committed long-term facilities serve to backup the issuance of commercial paper or to provide liquidity support.

(b)SCE&G, Fuel Company and PSNC Energy may issue commercial paper in the amounts of up to $350 million, $250 million and $250 million, respectively.  Nuclear and fossil fuel inventories and emission allowances are financed through the issuance by Fuel Company of short-term commercial paper or LOC advances.

The committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks.  Wells Fargo Bank, N. A. provides 18.9% of the aggregate $1.1 billion credit facilities, Bank of America, N. A. provides 14.3%, Branch Banking and Trust Company, UBS Loan Finance LLC, Morgan Stanley Bank, and Credit Suisse, each provide 10.9%, and The Bank of New York and Mizuho Corporate Bank, Ltd each provide 9.1%.  Three other banks provide the remaining 5.0%.  These bank credit facilities support the issuance of commercial paper by SCE&G (including Fuel Company) and PSNC Energy.  In addition, a portion of the credit facilities supports SCANA’s borrowing needs.  When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCE&G (including Fuel Company) and PSNC Energy.

As of June 30, 2010, the Company had drawn $150 million from its $1.1 billion facilities, had approximately $231 million in commercial paper borrowings outstanding, was obligated under $3 million in LOC-supported letters of credit, and had approximately $82 million in cash and temporary investments.  The Company regularly monitors the commercial paper and short-term credit markets to optimize the timing for repayment of the outstanding balance on its draws, while maintaining appropriate levels of liquidity.

30

At June 30, 2010, the Company had net available liquidity of approximately $798 million, and the Company’s revolving credit facilities are in place until December 2011.  The Company’s overall debt portfolio has a weighted average maturity of approximately 15 years and bears an average cost of 6.1%.  A significant portion of long-term debt, other than credit facility draws, bears fixed interest rates or is swapped to fixed.  To further preserve liquidity, the Company rigorously reviews its projected capital expenditures and operating costs and adjusts them where possible without impacting safety, reliability, and core customer service.

In March 2010, PSNC Energy issued $100 million of 6.54% unsecured notes due March 30, 2020.   Proceeds from these notes were used to pay down short-term debt and for general corporate purposes.

SCANA issued stock valued at $48.8 million during the six months ended June 30, 2010 through various compensation and dividend reinvestment plans.  In addition, SCANA issued common stock valued at $59.2 million (at time of issue) in a public offering on May 17, 2010, and entered into forward sale contracts for approximately 6.6 million common shares to be sold over the next 22 months.

OTHER MATTERS

Off-Balance Sheet Transactions

Although SCANA invests in securities and business ventures, it does not hold significant investments in unconsolidated special purpose entities.  SCANA does not engage in off-balance sheet financing or similar transactions, although it is party to incidental operating leases in the normal course of business, generally for office space, furniture, equipment and rail cars.

Nuclear Generation

SCE&G and Santee Cooper have entered into a contractual agreement for the design and construction of two 1,117-megawatt nuclear electric generation units at the site of Summer Station.  SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the units, with SCE&G responsible for 55 percent of the cost and receiving 55 percent of the output, and Santee Cooper responsible for and receiving the remaining 45 percent.  Assuming timely receipt of federal approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, and the second in 2019.  SCE&G’s share of the estimated cash outlays (future value) totals $6.0 billion for plant costs and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC.

SCE&G’s latest Integrated Resource Plan filed with the SCPSC on February 26, 2010 continues to support SCE&G’s need for 55% of the output of the two new nuclear electric generating units to be constructed at Summer Station.  SCE&G has been advised by Santee Cooper that, in light of recent developments, it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the two units.  If Santee Cooper’s ownership interest in one or both of the units changes, SCE&G believes that one or more additional parties will be available to participate as joint owners.

SCE&G is unable to predict whether any change in Santee Cooper’s ownership interest or the addition of new joint owners will increase project costs or delay the commercial operation dates of the new units.  Any such project cost increase or delay could be material.

Environmental Matters; Claims and Litigation

The following discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations appearing in SCANA’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2009.  Below are updates representing important changes to the Environmental Matters discussion in that Form 10-K, as amended.

Air Quality

In June 2010, the EPA issued a final rule for a one-hour ambient air quality standard for sulfur dioxide emissions.  Initial evaluation of this new standard indicated that SCE&G’s McMeekin Station in Lexington County may be required to reduce its sulfur dioxide emissions to a level determined by EPA and/or DHEC.  The costs incurred to comply with this new standard are expected to be recovered through rates.

31

Hazardous and Solid Wastes

The EPA issued proposed rules, published in the Federal Register on June 21, 2010, to regulate CCR.  The proposal sets forth two primary options: (1) Regulate CCRs as non-hazardous wastes under Subtitle D of RCRA, and (2) Regulate CCRs under RCRA’s Subtitle C hazardous waste controls. EPA also proposed for comment a Subtitle D “Prime” option which would allow some surface impoundments to continue to operate for the remainder of their useful life. The EPA did not list a preferred option nor can the Company predict which option, if any, will be finalized. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when any new regulations are finalized. Any additional costs imposed by such regulations are expected to be recoverable through rates. Currently, the Company is evaluating the effect on groundwater quality from past and current CCR operations, which may result in operational changes and additional measures.

At the state level, recent changes in the waste characterization of coal ash have resulted in the reclassification of the waste from a Class II to Class III waste.  Therefore, modifications to the Company’s Class II landfills and disposal practices are necessary in order to comply with the more stringent Class III requirements. Although the modifications will result in increased disposal costs, the Company believes that any additional costs imposed by such regulations would be recoverable through rates.

Retail Gas Marketing

As Georgia’s regulated provider, SCANA Energy provides service to low-income customers and customers unable to obtain or maintain natural gas service from other marketers at rates approved by the GPSC, and SCANA Energy receives funding from the Universal Service Fund to offset some of the bad debt associated with the low-income group.  On July 22, 2010 the GPSC voted to extend the current two year term for SCANA Energy by one year to August 31, 2012.

Financial Regulatory Reform

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act became law.  This Act provides for substantial additional regulation of over-the-counter and security-based derivative instruments, among other things, and will require numerous rule-makings by the Commodity Futures Trading Commission and the SEC to implement.  The Company cannot predict when the final regulations will be issued or what requirements they will impose.

For additional information related to environmental matters and claims and litigation, see Notes 7B and 7C to the condensed consolidated financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk - The Company’s market risk exposures relative to interest rate risk have not changed materially compared with the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2009.  Interest rates on a significant portion of the Company’s outstanding long-term debt, other than credit facility draws, are fixed either through the issuance of fixed rate debt or through the use of interest rate derivatives.  The Company is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near future.  For further discussion of changes in long-term debt and interest rate derivatives, see ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – LIQUIDITY AND CAPITAL RESOURCES and also Notes 3 and 5 of the condensed consolidated financial statements.

32

Commodity price risk - The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  See Note 5 of the condensed consolidated financial statements.  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 for these or similar instruments.

Expected Maturity:
Futures Contracts		Options
			Purchased Call	Purchased Put	Sold Put	Sold Call
2010	Long	2010	(Long)	(Short)	(Long)	(Short)
Settlement Price (a)	4.87	Strike Price (a)	6.37	4.73	4.73	6.78
Contract Amount (b)	10.0	Contract Amount (b)	33.2	0.6	0.6	2.2
Fair Value (b)	9.7	Fair Value (b)	1.1	0.1	(0.1)	(0.1)
2011		2011
Settlement Price (a)	5.34	Strike Price (a)	6.54	5.00	5.00	6.88
Contract Amount (b)	10.6	Contract Amount (b)	38.6	0.2	0.2	1.2
Fair Value (b)	10.4	Fair Value (b)	2.0	-	-	-
(a)  Weighted average, in dollars
(b)  Millions of dollars

Swaps	2010	2011	2012	2013
Commodity Swaps:
Pay fixed/receive variable (b)	39.9	37.6	11.5	4.0
Average pay rate (a)	5.9694	6.1867	6.7198	7.6436
Average received rate (a)	4.8902	5.3529	5.6829	5.8984
Fair value (b)	32.7	32.5	9.7	3.1
Pay variable/receive fixed (b)	22.5	24.0	6.7	0.3
Average pay rate (a)	4.8533	5.3487	5.6769	5.9330
Average received rate (a)	5.5573	6.0089	6.2698	5.7850
Fair value (b)	25.8	26.9	7.4	0.3
Basis Swaps:
Pay fixed/receive variable (b)	13.9	13.1	3.5	2.8
Average pay rate (a)	4.8229	5.3670	5.7508	5.9847
Average received rate (a)	4.8250	5.3879	5.7176	5.8926
Fair value (b)	13.9	13.2	3.5	2.8
(a) Weighted average, in dollars
(b) Millions of dollars

ITEM 4. CONTROLS AND PROCEDURES

As of June 30, 2010, SCANA conducted an evaluation under the supervision and with the participation of its management, including its CEO and 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, 2010, 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, 2010 that has materially affected or is reasonably likely to materially affect SCANA’s internal control over financial reporting.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

FINANCIAL SECTION

34

ITEM 1. FINANCIAL STATEMENTS

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,			December 31,
Millions of dollars	2010			2009
Assets
Utility Plant In Service	$	9,699		$	9,286
Accumulated Depreciation and Amortization		(3,009	)		(2,926	)
Construction Work in Progress		1,080			1,138
Nuclear Fuel, Net of Accumulated Amortization		79			97
Utility Plant, Net		7,849			7,595
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation		43			42
Assets held in trust, net - nuclear decommissioning		70			69
Other investments		4			-
Nonutility Property and Investments, Net		117			111
Current Assets:
Cash and cash equivalents		21			134
Receivables, net of allowance for uncollectible accounts of $3 and $3		394			397
Receivables - affiliated companies		14			41
Inventories (at average cost):
Fuel and gas supply		225			259
Materials and supplies		115			107
Emission allowances		8			10
Prepayments and other		98			89
Total Current Assets		875			1,037
Deferred Debits and Other Assets:
Regulatory assets		1,025			936
Other		125			134
Total Deferred Debits and Other Assets		1,150			1,070
Total	$	9,991		$	9,813

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	June 30,		December 31,
Millions of dollars	2010		2009
Capitalization and Liabilities
Common equity	$	3,298	$	3,162
Noncontrolling interest		99		97
Long-Term Debt, net		3,048		3,158
Total Capitalization		6,445		6,417
Current Liabilities:
Short-term borrowings		231		254
Current portion of long-term debt		168		18
Accounts Payable		174		250
Affiliated Payables		161		144
Customer deposits and customer prepayments		60		51
Taxes accrued		1		128
Interest accrued		50		51
Dividends declared		47		50
Other		126		43
Total Current Liabilities		1,018		989
Deferred Credits and Other Liabilities:
Deferred income taxes, net		1,088		972
Deferred investment tax credits		69		111
Asset retirement obligations		470		458
Due to parent - postretirement and other benefits		194		195
Regulatory liabilities		655		639
Other		52		32
Total Deferred Credits and Other Liabilities		2,528		2,407
Commitments and Contingencies (Note 7)		-		-
Total	$	9,991	$	9,813

See Notes to Condensed Consolidated Financial Statements.

36

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

		Three Months Ended						Six Months Ended
		June 30,						June 30,
Millions of dollars		2010			2009			2010			2009
Operating Revenues:
Electric	$	577		$	524		$	1,119		$	1,024
Gas		75			72			255			229
Total Operating Revenues		652			596			1,374			1,253
Operating Expenses:
Fuel used in electric generation		223			191			459			377
Purchased power		3			3			5			8
Gas purchased for resale		48			48			167			153
Other operation and maintenance		128			126			260			250
Depreciation and amortization		66			68			133			135
Other taxes		46			41			89			82
Total Operating Expenses		514			477			1,113			1,005
Operating Income		138			119			261			248
Other Income (Expense):
Other income		3			4			7			6
Other expenses		(3	)		(3	)		(6	)		(6	)
Interest charges, net of allowance for borrowed funds
used during construction of $3, $6, $5 and $11		(46	)		(38	)		(93	)		(78	)
Allowance for equity funds used during construction		7			7			10			14
Total Other Expense		(39	)		(30	)		(82	)		(64	)
Income Before Income Tax Expense, Losses from Equity
Method Investments and Preferred Stock Dividends		99			89			179			184
Income Tax Expense		35			28			51			60
Income Before Losses From Equity Method Investments		64			61			128			124
Losses from Equity Method Investments		(1	)		-			(1	)		-
Net Income		63			61			127			124
Less Net Income Attributable to Noncontrolling Interest		3			2			5			3
Net Income Attributable to SCE&G		60			59			122			121
Preferred Stock Cash Dividends Declared		-			2			-			4
Earnings Available to Common Shareholder	$	60		$	57		$	122		$	117
Dividends Declared on Common Stock	$	47		$	43		$	94		$	84

See Notes to Condensed Consolidated Financial Statements.

37

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
Millions of dollars		2010			2009
Cash Flows From Operating Activities:
Net income	$	127		$	124
Adjustments to reconcile net income to net cash provided from operating activities:
Earnings from equity method investments, net of distribution		1			-
Deferred income taxes, net		115			30
Depreciation and amortization		140			144
Amortization of nuclear fuel		18			11
Allowance for equity funds used during construction		(10	)		(14	)
Carrying cost recovery		(3	)		(3	)
Cash provided (used) by changes in certain assets and liabilities:
Receivables		(11	)		77
Inventories		7			(43	)
Prepayments and other		(9	)		48
Regulatory assets		(91	)		(110	)
Regulatory liabilities		(2	)		20
Accounts payable		(19	)		(3	)
Taxes accrued		(127	)		(39	)
Interest accrued		(1	)		-
Changes in other assets		(4	)		(23	)
Changes in other liabilities		79			(57	)
Net Cash Provided From Operating Activities		210			162
Cash Flows From Investing Activities:
Utility property additions and construction expenditures		(396	)		(370	)
Proceeds from investments and sale of assets		8			(2	)
Nonutility property additions		(1	)		15
Investment in affiliate		41			18
Purchase of investments		(12	)		(1	)
Net Cash Used For Investing Activities		(360	)		(340	)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt		51			176
Repayment of long-term debt		(11	)		(132	)
Dividends		(97	)		(87	)
Contributions from parent		105			180
Short-term borrowings –affiliate, net		12			12
Short-term borrowings, net		(23	)		82
Net Cash Provided From Financing Activities		37			231
Net Increase (Decrease) In Cash and Cash Equivalents		(113	)		53
Cash and Cash Equivalents, January 1		134			119
Cash and Cash Equivalents, June 30	$	21		$	172
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $5 and $11)	$	87		$	75
- Income taxes		31			(2	)
Noncash Investing and Financing Activities:
Accrued construction expenditures		89			111

See Notes to Condensed Consolidated Financial Statements.

38

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Millions of dollars	2010			2009			2010				2009
Net Income	$	63		$	61		$	127		$	124
Other Comprehensive Income, net of tax:
Reclassification to net income - amortization of deferred
employee benefit plan costs, net of taxes		-			1			1			2
Total Comprehensive Income		63			62			128			126
Less comprehensive income attributable to noncontrolling interest		(3	)		(4	)		(5	)		(7	)
Comprehensive income available to common shareholder (1)	$	60		$	58		$	123		$	119

(1)  Accumulated other comprehensive loss totaled $31.8 million as of June 30, 2010 and $33.0 million as of December 31, 2009.

See Notes to Condensed Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in SCE&G’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2009.  These are interim financial statements and, due to the seasonality of Consolidated SCE&G’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

An enterprise’s consolidated financial statements are required to include entities for which the enterprise holds a primary beneficial interest.  SCE&G has determined that it holds a primary beneficial interest in GENCO and 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.  Accordingly, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements.

GENCO owns a coal-fired electric generating station with a 570 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 $501.7 million) serves as collateral for its long-term borrowings.

B.Basis of Accounting

Consolidated SCE&G has significant cost-based, rate-regulated operations and recognizes in its financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated.  As a result, Consolidated SCE&G has recorded regulatory assets and regulatory liabilities, which are summarized in the following tables.  Substantially all of our regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.

	June 30,		December 31,
Millions of dollars	2010		2009
Regulatory Assets:
Accumulated deferred income taxes	$	167	$	167
Under collections – electric fuel adjustment clause	62		55
Environmental remediation costs	26		19
Asset retirement obligations and related funding	276		265
Franchise agreements	47		50
Deferred employee benefit plan costs	307		306
Planned major maintenance	4		5
Deferred losses on interest rate derivatives	108		50
Other	28		19
Total Regulatory Assets	$	1,025	$	936
Regulatory Liabilities:
Accumulated deferred income taxes	$	27	$	29
Other asset removal costs	552		535
Storm damage reserve	46		44
Deferred gains on interest rate derivatives	28		29
Other	2		2
Total Regulatory Liabilities	$	655	$	639

40

Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset.  Substantially all of these regulatory assets are expected to be recovered over the remaining lives of the related property which may range up to approximately 70 years.  Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.

Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC during annual hearings which are expected to be recovered in retail electric rates in future periods.  These amounts are expected to be recovered in retail electric rates during the period May 2011 through April 2012.  SCE&G is allowed to recover interest on actual base fuel deferred balances through the recovery period.

Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by SCE&G.  These regulatory assets are expected to be recovered over approximately 23 years.

ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs.  These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 95 years.

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.

Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders.  A significant majority of these deferred costs are expected to be recovered through utility rates over average service periods of participating employees, or up to approximately 14 years.

Planned major maintenance related to certain fossil hydro turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved through specific SCPSC orders.  SCE&G is presently collecting and will continue to collect $8.5 million annually through July 15, 2010, through electric rates to offset turbine maintenance expenditures.  After July 15, 2010, SCE&G will collect $18.4 million annually for this purpose.  Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.

Deferred losses or gains on interest rate derivatives represent the effective portions of changes in fair value and payments made or received upon termination of certain interest rate swaps, treasury rate locks and forward starting swap agreements designated as cash flow hedges.  These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years.

Various other regulatory assets are expected to be recovered in rates over periods of up to 30 years.

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

The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year, certain transmission and distribution insurance premiums and certain tree trimming and vegetation management expenditures in excess of amounts included in base rates.  During the six months ended June 30, 2010 and 2009, SCE&G applied costs of $1.5 million and $1.4 million, respectively, to the reserve.  Pursuant to SCPSC’s July 2010 order approving an electric rate increase, SCE&G suspended collection of storm damage reserve funds indefinitely pending future SCPSC action and, effective January 2011, SCE&G will no longer apply tree trimming and vegetation management expenditures against the reserve.

41

The SCPSC or the FERC have reviewed and approved through specific orders most of the items shown as regulatory assets.  Other regulatory assets include certain costs which have not been approved for recovery by the SCPSC or by FERC.  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.  In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, Consolidated SCE&G could be required to write off its regulatory assets and liabilities.  Such an event could have a material adverse effect on Consolidated SCE&G’s results of operations, liquidity or financial position in the period the write-off would be recorded.

C.Affiliated Transactions

CGT 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 $2.5 million and $2.8 million payable to CGT for transportation services at June 30, 2010 and December 31, 2009, respectively.

SCE&G purchases natural gas and related pipeline capacity from SEMI to supply its Jasper County Electric Generating Station, Urquhart Electric Generation Station and to serve its retail gas customers.  Such purchases totaled approximately $89.0 million and $78.9 million for the six months ended June 30, 2010 and 2009, respectively.  SCE&G’s payables to SEMI for such purposes were $17.8 million and $13.8 million as of June 30, 2010 and December 31, 2009, respectively.

SCE&G owns 40% of Canadys Refined Coal, LLC and 10% of Cope Refined Coal, LLC, both involved in the manufacturing and selling of refined coal to reduce emissions.  SCE&G’s receivables from these affiliates were $14.0 million at June 30, 2010.  SCE&G’s payables to these affiliates were $14.1 million at June 30, 2010.  SCE&G accounts for these investments using the equity method.

Consolidated SCE&G participates in a utility money pool.  Money pool borrowings and investments bear interest at short-term market rates.  Consolidated SCE&G’s interest income and interest expense on money pool borrowings was not significant for the six months ended June 30, 2010 and 2009.  At June 30, 2010 and December 31, 2009, Consolidated SCE&G owed an affiliate $82.0 million and $29.2 million, respectively.

D.Pension and Other Postretirement Benefit Plans

Consolidated SCE&G participates in SCANA’s noncontributory defined benefit pension plan, which covers substantially all permanent employees, and also participates in SCANA’s unfunded postretirement health care and life insurance programs, which provide benefits to active and retired employees.   Consolidated SCE&G’s net periodic benefit cost for the pension plan was $5.0 million and $10.2 million for the three and six months ended June 30, 2010, respectively, and $8.4 million and $16.7 million for the corresponding periods in 2009 (which include deferred amounts, see below).  Net periodic benefit cost for the postretirement plan was $3.5 million and $7.0 million for the three and six months ended June 30, 2010, respectively, and was $3.4 million and $6.7 million for the corresponding periods in 2009.

Through July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension expense above that which is included in current rates for SCE&G’s retail electric and gas distribution regulated operations.  In connection with the SCPSC’s July 2010 electric rate order, SCE&G began deferring all pension expense or income related to retail electric operations as a regulatory asset or liability, as applicable.  Costs totaling $5.3 million and $10.7 million were deferred for the three and six months ended June 30, 2010, respectively.  Costs totaling $7.8 million and $15.6 million were deferred for the corresponding period in 2009.

E.New Accounting Matters

Effective January 1, 2010, Consolidated SCE&G adopted accounting guidance that requires additional disclosures for assets and liabilities recorded at fair value.  This guidance requires disclosure of fair values for each class of assets and liabilities.  In addition, when the basis for measuring the fair value of a previously recorded asset or liability changes, this guidance requires disclosure of values transferred between Levels 1 and 2 of the fair value hierarchy, if significant.  The initial adoption of this guidance did not impact Consolidated SCE&G’s results of operations, cash flows or financial position.

42

Effective January 1, 2010, Consolidated SCE&G adopted accounting guidance that replaces the quantitative based calculation for determining which reporting entity has a controlling interest in a variable interest entity with a qualitative approach.  The guidance also requires additional disclosures about a reporting entity’s involvement with variable interest entities and any significant changes in risk exposure.  The initial adoption of this guidance did not impact Consolidated SCE&G’s results of operations, cash flows or financial position.

F.Income Taxes

In the first quarter of 2010, in connection with a fuel cost recovery settlement (see Note 2), SCE&G accelerated the recognition of certain previously deferred state income tax credits.  In the second quarter of 2010, SCE&G revised (reduced) its estimate of the benefit to be realized from the domestic production activities deduction as a result of a change in method of accounting for certain repairs for tax purposes.

No material changes in the status of Consolidated SCE&G’s tax positions have occurred through June 30, 2010.

2.REGULATORY MATTERS

Electric

SCE&G’s electric rates are established using a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G.  Effective with the first billing cycle of May 2010, the SCPSC approved a settlement agreement authorizing SCE&G to decrease the fuel cost portion of its electric rates.  The settlement agreement incorporated SCE&G’s proposal to accelerate the recognition of $17.4 million of previously deferred state income tax credits and record an offsetting reduction to the recovery of fuel costs.  In addition, SCE&G agreed to defer recovery of its actual undercollected base fuel costs as of April 30, 2010 for the period of May 1, 2010 through April 30, 2011.  SCE&G is allowed to charge and recover carrying costs monthly on the actual base fuel costs undercollected balance as of the end of each month during this deferral period.

On July 15, 2010, the SCPSC issued an order approving a 4.88% overall increase in SCE&G’s retail electric base rates and authorized an allowed return on common equity of 10.7%.  The SCPSC’s order adopted various stipulations among SCE&G, the ORS and other intervening parties.  Among other things, the SCPSC’s order included implementation of a pilot weather normalization mechanism for SCE&G’s electric customers, which will begin in August 2010, provided for a $25 million credit to SCE&G’s customers based on first quarter 2010 weather-related revenues, provided for a $48.7 million credit to SCE&G’s customers over two years for previously deferred state income tax credits and provided for the recovery of certain federally-mandated capital expenditures that had been included in utility plant but were not being depreciated.

On July 15, 2010, the SCPSC issued an order approving the implementation by SCE&G of certain DSM Programs, including the establishment of an annual rider to allow recovery of the costs and lost net margin revenue associated with DSM Programs, along with an incentive for investing in such programs.  The SCPSC’s order approved various settlement agreements among SCE&G, the ORS and other intervening parties.

In December 2009, SCE&G submitted to the FERC revised tariff sheets to change the network and point to point transmission rates under SCE&G’s OATT.  The request, if approved, would result in an annual revenue increase of $5.6 million.  In compliance with the OATT, on March 1, 2010 pursuant to an order issued by the FERC, SCE&G implemented, subject to refund, the proposed tariff sheets.  On May 17, 2010, SCE&G submitted to the FERC as an informational filing its recalculated Annual Transmission Revenue Requirement or “Annual Update” for the period June 1, 2010 through May 31, 2011.  The FERC accepted the tariff sheets in the “Annual Update” and made them effective subject to refund as of June 1, 2010.

Electric – BLRA

In January 2010, the SCPSC approved SCE&G’s request for an order pursuant to the BLRA to approve an updated construction and capital cost schedule for the construction of two new nuclear generating units at Summer Station.  The updated schedule provides details of the construction and capital cost schedule beyond what was proposed and included in the original BLRA filing described below.  The revised schedule does not change the previously announced completion date for the new units or the originally announced cost.

In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the BLRA seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to the

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proposed construction and operation by SCE&G and Santee Cooper of two new nuclear generating units at Summer Station.  Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built.  The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, including contingencies, as approved by the SCPSC.  As part of its order, the SCPSC approved the initial rate increase of $7.8 million, or 0.4%, related to recovery of the cost of capital on project expenditures through June 30, 2008, and the revised rates became effective for bills rendered on and after March 29, 2009.  In May 2009, two intervenors filed separate appeals of the order (one of which challenged the SCPSC’s prudency finding) with the South Carolina Supreme Court.  With regard to the first appeal, which challenged the SCPSC’s prudency finding, the South Carolina Supreme Court issued an opinion on April 26, 2010, affirming the decision of the SCPSC.  As for the second appeal, the South Carolina Supreme Court heard oral arguments on April 6, 2010.  SCE&G cannot predict how or when the Court will rule.

Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation.  Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%.  In September 2009, the SCPSC approved SCE&G’s annual revised rate request under the BLRA which constituted a $22.5 million or 1.1% increase to retail electric rates.  On May 28, 2010, SCE&G filed with the SCPSC for its annual revised rate request under the BLRA.  If approved, SCE&G expects this request will constitute a $47.0 million, or 2.3%, increase to retail electric rates.

Gas

The RSA 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 infrastructure.   On June 15, 2010, pursuant to the annual RSA filing, SCE&G requested a decrease in retail natural gas rates of $10.1 million.  If approved by the SCPSC, the rate adjustment will be effective with the first billing cycle of November 2010.  In October 2009, the SCPSC approved an increase in SCE&G’s retail natural gas base rates of $13.0 million under the terms of the RSA.  The rate adjustment was effective with the first billing cycle of November 2009.

SCE&G’s tariffs include a PGA clause that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities.  SCE&G’s rates are calculated using a methodology which adjusts the cost of gas monthly based on a 12-month rolling average.  In December 2009, in connection with the annual review of the PGA and the gas purchasing policies of SCE&G, the SCPSC determined that SCE&G’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 17 months ended July 31, 2009.  The SCPSC has scheduled a public hearing for November 10, 2010 to conduct its annual review of the PGA and gas purchasing policies of SCE&G for the 12 months ended July 31, 2010.

3.LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

Substantially all of Consolidated SCE&G’s electric utility plant is pledged as collateral in connection with long-term debt. Consolidated SCE&G is in compliance with all debt covenants.

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Liquidity

SCE&G (including Fuel Company) had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:

	Consolidated SCE&G (a)(b)
		June 30,			December 31,
Millions of dollars		2010			2009
Lines of credit:
Committed long-term (expire December 2011)
Total	$	650		$	650
LOC advances		150			100
Weighted average interest rate		.62	%		.50	%
Outstanding commercial paper (270 or fewer days)		231			254
Weighted average interest rate		.45	%		.33	%
Letters of credit supported by LOC		.3			.3
Available		269			296

(a)Consolidated SCE&G’s committed long-term facilities serve to backup the issuance of commercial paper or to provide liquidity support.

(b)SCE&G and Fuel Company may issue commercial paper in the amounts of up to $350 million for SCE&G and up to $250 million for Fuel Company.  Nuclear and fossil fuel inventories and emission allowances are financed through the issuance by Fuel Company of short-term commercial paper or LOC advances.

The committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks.  Wells Fargo Bank, N. A provides 18.9% of the aggregate $650 million credit facilities, Bank of America, N.A. provides 14.3%, Branch Banking and Trust Company, UBS Loan Finance LLC, Morgan Stanley Bank, and Credit Suisse, each provide 10.9%, and The Bank of New York and Mizuho Corporate Bank, Ltd each provide 9.1%.  Three other banks provide the remaining 5.0%.  These bank credit facilities support the issuance of commercial paper by SCE&G (including Fuel Company).  When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCE&G (including Fuel Company).

4.COMMON EQUITY

Changes in common equity during the six months ended June 30, 2010 and 2009 were as follows:

Millions of dollars		Common Equity			Noncontrolling Interest			Total Equity
Balance at January 1, 2010	$	3,162		$	97		$	3,259
Capital contribution from parent		105			-			105
Dividends declared		(91	)		(3	)		(94	)
Net income		122			5			127
Balance as of June 30, 2010	$	3,298		$	99		$	3,397

Balance at January 1, 2009	$	2,704	$	95		$	2,799
Capital contribution from parent		182		-			182
Dividends declared		(86)		(2	)		(88	)
Net income		121		3			124
Balance as of June 30, 2009	$	2,921	$	96		$	3,017

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5.DERIVATIVE FINANCIAL INSTRUMENTS

Consolidated SCE&G recognizes all derivative instruments as either assets or liabilities in the statement of financial position and measures those instruments at fair value.  Consolidated SCE&G recognizes changes in the fair value of derivative instruments either in earnings or within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation.  The fair value of derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or, for interest rate swaps, discounted cash flow models with independently sourced data.

Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by Consolidated SCE&G.  SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries, including Consolidated SCE&G.  The Risk Management Committee, which is comprised of certain officers, including Consolidated SCE&G’s Risk Management Officer and senior officers, apprises the Board of Directors with regard to the management of risk and brings to the Board’s attention any areas of concern.  Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

Commodity Derivatives

SCE&G uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations.  Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas.  The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy and financial institutions.

SCE&G’s tariffs include a 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, the cost of derivatives and gains and losses on such 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.  These derivative financial instruments are not designated as hedges for accounting purposes.

Interest Rate Swaps

Consolidated SCE&G uses interest rate swaps to manage interest rate risk on certain debt issuances and to synthetically convert variable rate debt to fixed rate debt.  In addition, in anticipation of the issuance of debt, Consolidated SCE&G may use treasury rate lock or forward starting swap agreements which are designated as cash flow hedges.  The effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities.  Ineffective portions of changes in fair value are recognized in income.

The effective portions of settlement payments made or received upon termination are amortized to interest expense over the term of the underlying debt and are classified as a financing activity in the consolidated statements of cash flows.

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Quantitative Disclosures Related to Derivatives

The Company was party to natural gas derivative contracts for 2,405,000 DT at June 30, 2010 and 2,365,000 DT at December 31, 2009.  The Company was a party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $421.4 million at June 30, 2010 and $71.4 million at December 31, 2009.

	Fair Values of Derivative Instruments
	Asset Derivatives				Liability Derivatives
		Balance Sheet		Fair	Balance Sheet		Fair
Millions of dollars		Location (a)		Value	Location (a)		Value
As of June 30, 2010
Derivatives designated as hedging instruments
Interest rate contracts		Other deferred debits	$	3	Other current liabilities	$	42
		Prepayments and other			Other deferred credits		18
Total			$	3		$	60
Derivatives not designated as hedging instruments
Commodity contracts		Prepayments and other	$	1
As of December 31, 2009
Derivatives designated as hedging instruments
Interest rate contracts		Other deferred debits	$	4	Other deferred credits	$	1
Derivatives not designated as hedging instruments
Commodity contracts		Prepayments and other	$	1

(a)Asset derivatives represent unrealized gains to Consolidated SCE&G, and liability derivatives represent unrealized losses.  In Consolidated SCE&G’s condensed consolidated balance sheet, unrealized gain and loss positions on commodity contracts with the same counterparty are reported as either a net asset or liability.

The effect of derivative instruments on the statements of income is as follows:

		Gain (Loss) Deferred		Gain (Loss) Reclassified from
Derivatives in Cash Flow		in Regulatory Accounts		Deferred Accounts into Income
Hedging Relationships		(Effective Portion)		(Effective Portion)
Millions of dollars				Location		Amount
Three Months Ended June 30, 2010
Interest rate contracts	$	(63	)	Interest expense	$	-
Six Months Ended June 30, 2010
Interest rate contracts	$	(60	)	Interest expense	$	(1	)
Three Months Ended June 30, 2009
Interest rate contracts	$	27		Interest expense	$	-
Six Months Ended June 30, 2009
Interest rate contracts	$	50		Interest expense	$	(1	)

	Gain (Loss) Recognized in Income
Derivatives Not Designated as
Hedging Instruments
Millions of dollars	Location		2010			2009
Second Quarter
Commodity contracts	Gas purchased for resale	$	(1	)	$	(3	)
Year to date
Commodity contracts	Gas purchased for resale	$	(2	)	$	(6	)

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Hedge Ineffectiveness

Other losses recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were $0.2 million and $0.1 million, net of tax for the three and six months ended June 30, 2010, respectively.  Other gains recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were $1.9 million and $2.0 million, net of tax, for the three and six months ended June 30, 2009, respectively.

Credit Risk Considerations

Certain of Consolidated SCE&G’s derivative instruments contain contingent provisions that require Consolidated SCE&G to provide collateral upon the occurrence of specific events, primarily credit downgrades.  As of June 30, 2010, Consolidated SCE&G has posted $8.3 million of collateral related to derivatives with contingent provisions that are in a net liability position.  If all of the contingent features underlying these instruments were fully triggered as of June 30, 2010, Consolidated SCE&G would be required to post an additional $51.3 million of collateral to its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of June 30, 2010 is $59.6 million.

6.FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

Consolidated SCE&G values commodity derivative assets and liabilities using unadjusted NYMEX prices, and considers such measure of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments.  Consolidated SCE&G’s interest rate swap agreements are valued using discounted cashflow models with independently sourced data.  Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:

		Fair Value Measurements Using
		Quoted Prices in Active			Significant Other
		Markets for Identical Assets			Observable Inputs
Millions of dollars		(Level 1)			(Level 2)
As of June 30, 2010
Assets -	Interest rate contracts		$	-		$	3
	Commodity contracts			1			-
Liabilities-	Interest rate contracts			-			60
As of December 31, 2009
Assets -	Interest rate contracts		$	-		$	4
	Commodity contracts			1			-
Liabilities -	Interest rate contracts			-			1

There were no fair value measurements based on significant unobservable inputs (Level 3) for either period presented.  In addition, there were no transfers of fair value amounts into or out of Levels 1 and 2 during any period presented.

The financial instruments for which the carrying amount may not equal estimated fair value at June 30, 2010 and December 31, 2009 were as follows:

	June 30, 2010				December 31, 2009
Millions of dollars	CarryingAmount		EstimatedFairValue		CarryingAmount		EstimatedFairValue
Long-term debt	$	3,216.1	$	3,569.9	$	3,175.1	$	3,330.4

Fair values of long-term debt are based on quoted market prices of the instruments or similar instruments.  For debt instruments for which no quoted market prices are available, fair values are based on net present value calculations.  Carrying values reflect the fair values of interest rate swaps based on discounted cash flow models with independently sourced data.  Early settlement of long-term debt may not be possible or may not be considered prudent.  Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been considered.

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7.COMMITMENTS AND CONTINGENCIES

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 $12.6 billion.  Each reactor licensee is currently liable for up to $117.5 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5 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 $78.3 million per incident, but not more than $11.7 million per year.

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station) with Nuclear Electric Insurance Limited.  The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer’s losses.  Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $14.2 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 rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer.  SCE&G has no reason to anticipate a serious nuclear incident. However, if such an incident were to occur, it likely would have a material adverse impact on the Company’s results of operations, cash flows and financial position.

B.Environmental

In December 2009, the EPA issued a final finding that atmospheric concentrations of GHG endanger public health and welfare within the meaning of Section 202(a) of the CAA.  The rule, which became effective in January 2010, enables the EPA to regulate GHG emissions under the CAA.  The EPA has committed to issue new rules regulating such emissions by November 2011.  On September 30, 2009, the EPA issued a proposed rule that would require facilities emitting over 25,000 tons of GHG a year (such as Consolidated SCE&G’s generating facilities) to obtain permits demonstrating that they are using the best practices and technologies to minimize GHG emissions.  Consolidated SCE&G expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

In 2005, the EPA issued the CAIR, which 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.  CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide.  Numerous states, environmental organizations, industry groups and individual companies challenged the rule, seeking a change in the method CAIR used to allocate sulfur dioxide emission allowances.  On December 23, 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the rule but did not vacate it.  Prior to the Court of Appeals’ decision, SCE&G and GENCO had determined that additional air quality controls would be needed to meet the CAIR requirements.  SCE&G has completed installation of a SCR technology at Cope Station for nitrogen oxide reduction, and GENCO has completed installation of a wet limestone scrubber at Williams Station for sulfur dioxide reduction.  SCE&G also installed a wet limestone scrubber at Wateree Station.  Consolidated SCE&G expects to incur capital expenditures totaling approximately $559 million through 2010 for these projects, of which the majority has already been spent.   EPA has proposed a revised rule which is currently being evaluated by the Company.  Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

In June 2010, the EPA issued a final rule for a one-hour ambient air quality standard for sulfur dioxide emissions.  Initial evaluation of this new standard indicated that SCE&G’s McMeekin Station in Lexington County may be required to reduce its sulfur dioxide emissions to a level determined by EPA and/or DHEC.  The costs incurred to comply with this new standard are expected to be recovered through rates.

In 2005, the EPA issued the CAMR, which established a mercury emissions cap and trade program for coal-fired power plants.  Numerous parties challenged the rule.  On February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units.  Consolidated SCE&G expects the EPA will issue a new rule on mercury emissions in 2011 but cannot predict what requirements it will impose.

SCE&G has been named, along with 53 others, by the EPA as a PRP at the AER Superfund site located in Augusta, Georgia.  The EPA placed the site on the National Priorities List in April 2006.  AER conducted hazardous waste storage and

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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 PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that was completed in 2010.  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 is expected to be recoverable through rates.

SCE&G maintains an environmental assessment program to identify and evaluate its current and former operations 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 cleanup costs and expects to recover them through rates.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC. SCE&G anticipates that major remediation activities at these sites will continue until 2012 and will cost an additional $10.2 million.  In addition, the National Park Service of the Department of the Interior has made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina.  SCE&G expects to recover any cost arising from the remediation of these four sites through rates.  At June 30, 2010, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.7 million.

C.Claims and Litigation

In May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette and Mark Rudd, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Communications, Inc. was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit.  The plaintiffs allege that SCE&G made improper use of certain electric transmission easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications.  The plaintiffs asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment, but did not assert a specific dollar amount for the claims.  SCE&G believes its actions are consistent with governing law and the applicable documents granting easements and rights-of-way.  In June 2007, the Circuit Court issued a ruling that limits the plaintiffs’ purported class to easement grantors situated in Charleston County, South Carolina.  In February 2008, the Circuit Court issued an order to conditionally certify the class, which remains limited to easements in Charleston County.  In July 2008, the plaintiffs’ motion to add SCI to the lawsuit as an additional defendant was granted.  SCE&G and SCI 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.

Consolidated SCE&G 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 Consolidated SCE&G’s results of operations, cash flows or financial condition.

D.Nuclear Generation

SCE&G and Santee Cooper have entered into a contractual agreement for the design and construction of two 1,117-megawatt nuclear electric generation units at the site of Summer Station.  SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the units, with SCE&G responsible for 55 percent of the cost and receiving 55 percent of the output, and Santee Cooper responsible for and receiving the remaining 45 percent.  Assuming timely receipt of federal approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, and the second in 2019.  SCE&G’s share of the estimated cash outlays (future value) totals $6.0 billion for plant costs and for related transmission infrastructure costs, which costs are projected based on historical one-year and five year escalation rates as required by the SCPSC.

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SCE&G’s latest Integrated Resource Plan filed with the SCPSC on February 26, 2010 continues to support SCE&G’s need for 55% of the output of the two units.  SCE&G has been advised by Santee Cooper that, in light of recent developments, it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the two units.  If Santee Cooper’s ownership interest in one or both of the units changes, SCE&G believes that one or more additional parties will be available to participate as joint owners.

SCE&G is unable to predict whether any change in Santee Cooper’s ownership interest or the addition of new joint owners will increase project costs or delay the commercial operation dates of the new units.  Any such project cost increase or delay could be material.

8.SEGMENT OF BUSINESS INFORMATION

Consolidated SCE&G’s reportable segments are listed in the following table.  Consolidated SCE&G uses operating income to measure profitability for its regulated operations.  Therefore, earnings available to common shareholder are not allocated to the Electric Operations and Gas Distribution segments.  Intersegment revenues were not significant.

						Earnings
			Operating			Available to
	External		Income			Common		Segment
Millions of Dollars	Revenue		(Loss)			Shareholder		Assets
Three Months Ended June 30, 2010
Electric Operations	$	577	$	139			n/a
Gas Distribution		75		-			n/a
Adjustments/Eliminations		-		(1	)	$	60
Consolidated Total	$	652	$	138		$	60

Six Months Ended June 30, 2010
Electric Operations	$	1,119	$	225			n/a	$	7,545
Gas Distribution		255		37			n/a		569
Adjustments/Eliminations		-		(1	)	$	122		1,877
Consolidated Total	$	1,374	$	261		$	122	$	9,991
Three Months Ended June 30, 2009
Electric Operations	$	524	$	121			n/a
Gas Distribution		72		(2	)		n/a
Adjustments/Eliminations		-		-		$	57
Consolidated Total	$	596	$	119		$	57

Six Months Ended June 30, 2009
Electric Operations	$	1,024	$	223			n/a	$	6,925
Gas Distribution		229		26			n/a		544
Adjustments/Eliminations		-		(1	)	$	117		1,942
Consolidated Total	$	1,253	$	248		$	117	$	9,411

For the three and six months ended June 30, 2010, operating income for Electric Operations reflects a reduction in recovery of fuel of $17.4 million in connection with the settlement described in Note 2.  This reduction was fully offset by recognition of tax benefits.

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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 SCE&G’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2009.

RESULTS OF OPERATIONS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2010

AS COMPARED TO THE CORRESPONDING PERIODS IN 2009

Net Income

Net income for Consolidated SCE&G was as follows:

	Second Quarter							Year to Date
Millions of dollars	2010		% Change			2009		2010	% Change			2009
Net income	$	62.7	2.6	%	$	61.1	$	126.5	1.6	%	$	124.5

Second Quarter

Net income increased by $13.6 million due to higher electric margin and $1.4 million due to higher gas margin.  These increases were partially offset by higher operating expenses of $3.5 million which are explained below and higher interest expense of $2.9 million.   All amounts are net of tax.  Consolidated SCE&G’s results of operations also include the effects of a higher effective tax rate in the second quarter of 2010.

Year to Date

Net income increased by $20.6 million due to higher electric margin (excluding the effect of the $17.4 million adjustment described at “Electric Operations”) and $7.8 million due to higher gas margin.  These increases were partially offset by higher operating expenses of $9.4 million which are explained below, lower equity AFC of $3.9 million and higher interest expense of $5.5 million.   All amounts are net of tax.  Consolidated SCE&G’s results of operations also include the effects of a higher effective tax rate in 2010 (excluding the effect of the adjustment referred to above and described at “Electric Operations”).

Dividends Declared

Consolidated SCE&G’s Board of Directors has declared the following dividends on common stock (all of which was held by SCANA) during 2010:

Declaration Date		Amount	Quarter Ended	Payment Date
February 11, 2010	$	46.6 million	March 31, 2010	April 1, 2010
May 6, 2010		47.2 million	June 30, 2010	July 1, 2010
July 29, 2010		50.7 million	September 30, 2010	October 1, 2010

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Electric Operations

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

		Second Quarter						Year to Date
Millions of dollars			2010	% Change			2009		2010	% Change			2009
Operating revenues		$	577.0	10.2	%	$	523.8	$	1,118.7	9.3	%	$	1,023.9
Less:	Fuel used in electric generation		223.0	16.6	%		191.3		459.0	21.6	%		377.4
	Purchased power		2.6	(16.1	)%		3.1		5.0	(36.7	)%		7.9
Margin		$	351.4	6.7	%	$	329.4	$	654.7	2.5	%	$	638.6

MWh sales volumes related to the electric margin above, by class, were as follows:

	Second Quarter				Year to Date
Classification (in thousands)	2010	% Change		2009	2010	% Change		2009
Residential	1,981	6.3	%	1,864	4,280	12.5	%	3,803
Commercial	1,941	3.4	%	1,878	3,685	3.4	%	3,563
Industrial	1,493	14.8	%	1,301	2,846	10.9	%	2,567
Sale for resale (excluding  interchange)	446	4.4	%	427	873	1.6	%	859
Other	143	2.9	%	139	273	0.7	%	271
Total territorial	6,004	7.0	%	5,609	11,957	8.1	%	11,063
Negotiated Market Sales Tariff (NMST)	22	(80.7	)%	114	28	(80.3	)%	142
Total	6,026	5.3	%	5,723	11,985	7.0	%	11,205

Second Quarter

Margin increased due to higher residential and commercial customer usage of $9.4 million, higher industrial sales of $1.2 million, customer growth of $2.0 million and an increase in base rates approved by the SCPSC under the BLRA of $5.9 million.

Territorial sales volume increased by 169 MWh due to increased average use and the effects of favorable weather and 189 MWh due to higher industrial sales volumes.

Year to Date

Margin increased due to higher residential and commercial customer usage of $34.0 million, higher industrial sales of $2.3 million, customer growth of $4.1 million and an increase in base rates approved by the SCPSC under the BLRA of $13.3 million.  Although weather was abnormally cold in the first quarter of 2010 and significantly colder than in the same period in 2009, estimated incremental revenues of $25 million associated with this weather have been deferred (for refund to customers) within other current liabilities based upon a stipulation related to SCE&G’s 2010 electric base rate case proceeding (see Note 2). Also, margin in the first quarter of 2010 was adjusted downward by $17.4 million pursuant to an SCPSC regulatory order issued in connection with SCE&G’s annual fuel cost proceeding.  (See also discussion at “Income Taxes”).

Territorial sales volume increased by 579 MWh due to increased average use and the effects of favorable weather and 277 MWh due to higher industrial sales volumes.

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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			2010	% Change			2009		2010	% Change			2009
Operating revenues		$	74.4	3.6	%	$	71.8	$	255.0	11.6	%	$	228.5
Less: Gas purchased for resale			47.9	0.8	%		47.5		166.7	9.1	%		152.8
Margin			26.5	9.1	%		24.3	$	88.3	16.6	%	$	75.7

DT sales volumes by class, including transportation gas, were as follows:

	Second Quarter				Year to Date
Classification (in thousands)	2010	% Change		2009	2010	% Change		2009
Residential	873	(22.7	)%	1,129	9,182	22.9	%	7,471
Commercial	2,489	(2.5	)%	2,553	7,286	5.4	%	6,911
Industrial	4,170	17.2	%	3,558	8,180	15.6	%	7,074
Transportation gas	5,231	7.0	%	4,888	8,653	7.0	%	8,086
Total	12,763	5.2	%	12,128	33,301	12.7	%	29,542

Second Quarter

Operating revenues and gas purchased for resale increased primarily due to increased customer usage.  Margin increased $2.1 million due to the SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2009.

Year to Date

Operating revenues and gas purchased for resale increased primarily due to increased customer usage.  Margin increased $3.9 million due to increased customer usage and $7.1 million due to the SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2009.

Other Operating Expenses

Other operating expenses were as follows:

	Second Quarter							Year to Date
Millions of dollars			2010	% Change			2009			2010	% Change			2009
Other operation and maintenance		$	127.7	1.4	%	$	125.9		$	259.6	4.1	%	$	249.4
Depreciation and amortization			66.4	(1.9	)%		67.7			132.8	(2.0	)%		135.5
Other taxes			46.0	12.7	%		40.8			89.6	9.4	%		81.9

Second Quarter

Other operation and maintenance expenses increased by $4.0 million due to higher incentive compensation and other benefits. This increase was partially offset by $2.5 million due to lower generation, transmission and distribution expenses. Depreciation and amortization expense decreased due to the adoption of new, lower depreciation rates in late 2009, partially offset by net property additions.  Other taxes increased primarily due to higher property taxes.

Year to Date

Other operation and maintenance expenses increased by $6.9 million due to higher incentive compensation and other benefits and by $3.5 million due to higher generation, transmission and distribution expenses.  Depreciation and amortization expense decreased due to the adoption of new, lower depreciation rates in late 2009, partially offset by net property additions.  Other taxes increased primarily due to higher property taxes.

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Other Income (Expense)

Other income (expense) includes the results of certain incidental (non-utility) activities.

Pension Cost

Pension cost was recorded on Consolidated SCE&G’s income statements and balance sheets as follows:

	Second Quarter							Year to Date
Millions of dollars			2010			2009			2010			2009
Income Statement Impact:
Reduction in employee benefit costs		$	(1.1	)	$	(1.1	)	$	(2.2	)	$	(2.2	)
Other income			(1.0	)		(1.0	)		(2.0	)		(2.1	)
Balance Sheet Impact:
Increase in capital expenditures			1.4			2.1			2.9			4.1
Component of amount payable from Summer Station co-owner			0.4			0.6			0.8			1.3
Regulatory asset			5.3			7.8			10.7			15.6
Total Pension Cost			5.0			8.4		$	10.2		$	16.7

No contribution to the pension trust will be necessary in or for 2010, nor will limitations on benefit payments apply.  Through July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost above that which was included in rates for its retail electric and gas distribution regulated operations.  In connection with the SCPSC’s July 2010 electric rate order, SCE&G will defer all pension expense and income related to retail electric operations as a regulatory asset or regulatory liability, as applicable.  These costs will be deferred until such time as future rate recovery is provided for by the SCPSC.

AFC

AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized.  Consolidated SCE&G includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income.  AFC decreased in 2010 due primarily to the completion of certain pollution abatement projects at coal-fired plants.

Interest Expense

Interest charges increased primarily due to increased borrowings.

Income Taxes

Second Quarter

Income taxes (and the effective tax rate) were higher in the second quarter of 2010 than in the second quarter of 2009 primarily due to the Company’s revision (reduction) in its estimate of the benefit to be realized from the domestic production activities deduction as a result of a change in method of accounting for certain repairs for tax purposes.

Year to Date

Income taxes (and the effective tax rate) for the six months ended June 30, 2010 reflect the above reduction of estimated benefit to be realized from the domestic production activities deduction (in the second quarter of 2010), which was more than offset by the recognition of certain previously deferred state income tax credits pursuant to the settlement of a fuel cost recovery proceeding in the first quarter of 2010 (see also the discussion at “Electric Operations”).

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LIQUIDITY AND CAPITAL RESOURCES

Consolidated SCE&G 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.  Consolidated SCE&G expects that, barring further impairment of the capital markets, it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future, including the cash requirements for nuclear construction and refinancing maturing long-term debt.  Consolidated SCE&G’s ratio of earnings to fixed charges for the six and 12 months ended June 30, 2010 was 2.79 and 3.14, respectively.

Consolidated SCE&G’s cash requirements arise primarily from its operational needs, funding its construction programs, payment of dividends to SCANA and refinancing of securities when deemed prudent.  The ability of Consolidated SCE&G 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.  Consolidated SCE&G’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, as requested.

Consolidated SCE&G’s issuance of various securities, including short- and long-term debt, is subject to customary approval or authorization by one or more state or federal regulatory bodies including the SCPSC and FERC.

During the period ended June 30, 2010, SCE&G has received from SCANA equity contributions of $25 million. Proceeds were received from SCANA’s various compensation and dividend reinvestment programs.  The contributed funds were used to finance capital expenditures, including the construction of new nuclear units, and for general corporate purposes.

SCE&G and GENCO have obtained FERC authority to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act).  SCE&G may issue up to $700 million of unsecured promissory notes or commercial paper with maturity of one year or less, and GENCO may issue up to $100 million of short-term indebtedness.  FERC’s approval expires in February 2012.

SCE&G (including Fuel Company) had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:

	Consolidated SCE&G  (a)(b)
		June 30,			December 31,
Millions of dollars		2010			2009
Lines of credit:
Committed long-term (expire December 2011)
Total	$	650		$	650
LOC advances		150			100
Weighted average interest rate		.62	%		.50	%
Outstanding commercial paper   (270 or fewer days)		231			254
Weighted average interest rate		.45	%		.33	%
Letters of credit supported by LOC		.3			.3
Available		269			296

(a)Consolidated SCE&G’s committed long-term facilities serve to backup the issuance of commercial paper or to provide liquidity support.

(b)SCE&G and Fuel Company may issue commercial paper in the amounts of up to $350 million for SCE&G and up to $250 million for Fuel Company.  Nuclear and fossil fuel inventories and emission allowances are financed through the issuance by Fuel Company of short-term commercial paper or LOC advances.

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The committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks.  Wells Fargo Bank, N. A provides 18.9% of the aggregate $650 million credit facilities, Bank of America, N.A. provides 14.3%, Branch Banking and Trust Company, UBS Loan Finance LLC, Morgan Stanley Bank, and Credit Suisse, each provide 10.9%, and The Bank of New York and Mizuho Corporate Bank, Ltd each provide 9.1%.  Three other banks provide the remaining 5.0%.  These bank credit facilities support the issuance of commercial paper by SCE&G (including Fuel Company).  When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCE&G (including Fuel Company).

As of June 30, 2010, Consolidated SCE&G had drawn $150 million from its $650 million facilities, had approximately $231 million in commercial paper borrowings outstanding, was obligated under $0.3 million in LOC-supported letters of credit and had approximately $21 million in cash and temporary investments.  Consolidated SCE&G regularly monitors the commercial paper and short-term credit markets to optimize the timing for repayment of the outstanding balance on its draws, while maintaining appropriate levels of liquidity.

At June 30, 2010, Consolidated SCE&G had net available liquidity of approximately $290 million, and Consolidated SCE&G’s revolving credit facilities are in place until December 2011.  Consolidated SCE&G’s overall debt portfolio has a weighted average maturity of approximately 17 years and bears an average cost of 5.8%.  A significant portion of long-term debt, other than credit facility draws, bears fixed interest rates or is swapped to fixed.  To further preserve liquidity, Consolidated SCE&G rigorously reviews its projected capital expenditures and operating costs and adjusts them where possible without impacting safety, reliability, and core customer service.

OTHER MATTERS

Off-Balance Sheet Transactions

SCE&G does not hold significant investments in unconsolidated special purpose entities.  SCE&G also does not engage in off-balance sheet financing or similar transactions, although it is party to incidental operating leases in the normal course of business, generally for office space, furniture, equipment and rail cars.

Nuclear Generation

SCE&G and Santee Cooper have entered into a contractual agreement for the design and construction of two 1,117-megawatt nuclear electric generation units at the site of Summer Station.  SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the units, with SCE&G responsible for 55 percent of the cost and receiving 55 percent of the output, and Santee Cooper responsible for and receiving the remaining 45 percent.  Assuming timely receipt of federal approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, and the second in 2019.  SCE&G’s share of the estimated cash outlays (future value) totals $6.0 billion for plant costs and for related transmission infrastructure costs, which costs are projected based on historical one-year and five year escalation rates as required by the SCPSC.

SCE&G’s latest Integrated Resource Plan filed with the SCPSC on February 26, 2010 continues to support SCE&G’s need for 55% of the output of the two new nuclear electric generating units to be constructed at Summer Station.  SCE&G has been advised by Santee Cooper that, in light of recent developments, it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the two units.  If Santee Cooper’s ownership interest in one or both of the units changes, SCE&G believes that one or more additional parties will be available to participate as joint owners.

SCE&G is unable to predict whether any change in Santee Cooper’s ownership interest or the addition of new joint owners will increase project costs or delay the commercial operation dates of the new units.  Any such project cost increase or delay could be material.

Environmental Matters; Claims and Litigation

The following discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations appearing in SCE&G’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2009.  Below are updates representing important changes to the Environmental Matters discussion in that Form 10-K, as amended.

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Air Quality

In June 2010, the EPA issued a final rule for a one-hour ambient air quality standard for sulfur dioxide emissions.  Initial evaluation of this new standard indicated that SCE&G’s McMeekin Station in Lexington County may be required to reduce its sulfur dioxide emissions to a level determined by EPA and/or DHEC.  The costs incurred to comply with this new standard are expected to be recovered through rates.

Hazardous and Solid Wastes

The EPA issued proposed rules, published in the Federal Register on June 21, 2010, to regulate CCR.  The proposal sets forth two primary options: (1) Regulate CCRs as non-hazardous wastes under Subtitle D of RCRA, and (2) Regulate CCRs under RCRA’s Subtitle C hazardous waste controls. EPA also proposed for comment a Subtitle D “Prime” option which would allow some surface impoundments to continue to operate for the remainder of their useful life. The EPA did not list a preferred option nor can Consolidated SCE&G predict which option, if any, will be finalized. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when any new regulations are finalized. Any additional costs imposed by such regulations are expected to be recoverable through rates. Currently, Consolidated SCE&G is evaluating the effect on groundwater quality from past and current CCR operations, which may result in operational changes and additional measures.

At the state level, recent changes in the waste characterization of coal ash have resulted in the reclassification of the waste from a Class II to Class III waste.  Therefore, modifications to Consolidated SCE&G’s Class II landfills and disposal practices are necessary in order to comply with the more stringent Class III requirements. Although the modifications will result in increased disposal costs, Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates.

Financial Regulatory Reform

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act became law.  This Act provides for substantial additional regulation of over-the-counter and security-based derivative instruments, among other things, and will require numerous rule-makings by the Commodity Futures Trading Commission and the SEC to implement.  SCE&G cannot predict when the final regulations will be issued or what requirements they will impose.

For additional information related to environmental matters and claims and litigation, see Notes 7B and 7C to the condensed consolidated financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk - Consolidated SCE&G’s market risk exposures relative to interest rate risk have not changed materially compared with SCE&G’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2009.  Interest rates on a significant portion of Consolidated SCE&G’s outstanding long-term debt, other than credit facility draws, are fixed either through the issuance of fixed rate debt or through the use of interest rate derivatives.  Consolidated SCE&G is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near future.  For further discussion of changes in long-term debt and interest rate derivatives, see ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - LIQUIDITY AND CAPITAL RESOURCES and also Notes 3 and 5 of the condensed consolidated financial statements.

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Commodity price risk - SCE&G uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  See Note 5 of the condensed consolidated financial statements.  The following table provides information about SCE&G’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 for these or similar instruments.

Expected Maturity:
Options
	Purchased Call
2010	(Long)
Strike Price (a)	6.14
Contract Amount (b)	8.8
Fair Value (b)	0.3
2011
Strike Price (a)	6.18
Contract Amount (b)	6.0
Fair Value(b)	0.4

(a)Weighted average, in dollars

(b)Millions of dollars

ITEM 4.  CONTROLS AND PROCEDURES

As of June 30, 2010, SCE&G conducted an evaluation under the supervision and with the participation of its management, including its CEO and 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, 2010, 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, 2010 that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.

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PART II.  OTHER INFORMATION

ITEM 6.  EXHIBITS

SCANA and 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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned 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 4, 2010	James E. Swan, IV
	Controller
	(Principal accounting officer)

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EXHIBIT INDEX

	Applicable to Form 10-Q of
Exhibit No.	SCANA	SCE&G	Description
3.01	X		Restated Articles of Incorporation of SCANA, 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 SCE&G, as adopted on December 30, 2009 (Filed asExhibit 1 to Form 8-A (File Number 000-53860) and incorporated by reference herein)
3.04	X		By-Laws of SCANA as amended and restated as of February 19, 2009 (Filed as Exhibit 3.01to Form 8-K filed February 23, 2009 and incorporated by reference herein)
3.05		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)
101. INS	X		XBRL Instance Document
101. SCH	X		XBRL Taxonomy Extension Schema
101. CAL	X		XBRL Taxonomy Calculation Linkbase
101. DEF	X		XBRL Taxonomy Definition Linkbase
101. LAB	X		XBRL Taxonomy Label Linkbase
101. PRE	X		XBRL Taxonomy Presentation Linkbase

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