10-Q

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, 2011

OR

oTRANSITION 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 x 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 27, 2011
SCANA Corporation	Without Par Value	129,019,800
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, 2011

			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	26
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33
	Item 4.	Controls and Procedures	34
South Carolina Electric & Gas Company Financial Section			35
	Item 1.	Financial Statements	36
		Condensed Consolidated Balance Sheets	36
		Condensed Consolidated Statements of Income	38
		Condensed Consolidated Statements of Cash Flows	39
		Condensed Consolidated Statements of Comprehensive Income	40
		Notes to Condensed Consolidated Financial Statements	41
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	54
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	60
	Item 4.	Controls and Procedures	61
PART II. OTHER INFORMATION			62
	Item 6.	Exhibits	62
Signatures			63
Exhibit Index			64

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, and actions affecting the construction of new nuclear units;
(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 and transmission;
(12)	maintaining creditworthy joint venture partners for SCE&G’s new nuclear generation project;
(13)	the ability of suppliers, both domestic and international, to timely provide the components, parts, tools, equipment and other supplies needed for our construction program, operations and maintenance;
(14)	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;
(15)	the availability of skilled and experienced human resources to properly manage, operate, and grow the Company’s businesses;
(16)	labor disputes;
(17)	performance of SCANA’s pension plan assets;
(18)	changes in taxes;
(19)	inflation or deflation;
(20)	compliance with regulations; and
(21)	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
AFC	Allowance for Funds Used During Construction
ARO	Asset Retirement Obligation
BLRA	Base Load Review Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CEO	Chief Executive Officer
CFO	Chief Financial Officer
CGT	Carolina Gas Transmission Corporation
COL	Combined Construction and Operating License
Company	SCANA, together with its consolidated subsidiaries
Consolidated SCE&G	SCE&G and its consolidated affiliates
CUT	Customer Usage Tracker
DHEC	South Carolina Department of Health and Environmental Control
DSM Programs	Demand reduction and energy efficiency programs
DT	Dekatherms
Duke	Duke Energy Carolinas
Energy Marketing	The divisions of SEMI, excluding SCANA Energy
EPA	United States Environmental Protection Agency
eWNA	Pilot Electric WNA
FEIS	Final Environmental Impact Statement
FERC	United States Federal Energy Regulatory Commission
FMPA	Florida Municipal Power Agency
Fuel Company	South Carolina Fuel Company, Inc.
GENCO	South Carolina Generating Company, Inc.
GWh	Gigawatt hour
LLC	Limited Liability Company
LOC	Lines of credit
MGP	Manufactured Gas Plant
NASDAQ	The NASDAQ Stock Market, Inc.
NCUC	North Carolina Utilities Commission
New Units	Nuclear Units 2 and 3 to be constructed at Summer Station
NRC	United States Nuclear Regulatory Commission
NYMEX	New York Mercantile Exchange
OATT	Open Access Transmission Tariff
OCI	Other Comprehensive Income
ORS	South Carolina Office of Regulatory Staff
OUC	Orlando Utilities Commission
PGA	Purchased Gas Adjustment
PRP	Potentially Responsible Party
PSNC Energy	Public Service Company of North Carolina, Incorporated
Retail Gas Marketing	SCANA Energy
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
SCEUC	South Carolina Energy Users Committee
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
USACE	United States Army Corps of Engineers
VIE	Variable Interest Entity
Westinghouse	Westinghouse Electric Company LLC
WNA	Weather Normalization Adjustment

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	2011			2010
Assets
Utility Plant In Service	$	11,901		$	11,714
Accumulated Depreciation and Amortization	(3,599		)	(3,495		)
Construction Work in Progress	1,284			1,081
Nuclear Fuel, Net of Accumulated Amortization	133			132
Goodwill, net of accumulated amortization and writedown of $276	230			230
Utility Plant, Net	9,949			9,662
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $127 and $118	302			299
Assets held in trust, net-nuclear decommissioning	80			76
Other investments	87			78
Nonutility Property and Investments, Net	469			453
Current Assets:
Cash and cash equivalents	166			55
Receivables, net of allowance for uncollectible accounts of $6 and $9	627			837
Inventories (at average cost):
Fuel and gas supply	284			316
Materials and supplies	128			125
Emission allowances	4			6
Prepayments and other	207			271
Deferred income taxes	19			21
Total Current Assets	1,435			1,631
Deferred Debits and Other Assets:
Regulatory assets	1,128			1,061
Other	163			161
Total Deferred Debits and Other Assets	1,291			1,222
Total	$	13,144		$	12,968

6

	June 30,		December 31,
Millions of dollars	2011		2010
Capitalization and Liabilities
Common Equity	$	3,805	$	3,702
Long-Term Debt, net	4,379		4,152
Total Capitalization	8,184		7,854
Current Liabilities:
Short-term borrowings	546		420
Current portion of long-term debt	286		337
Accounts payable	379		526
Customer deposits and customer prepayments	96		100
Taxes accrued	83		146
Interest accrued	74		72
Dividends declared	63		61
Derivative financial instruments	20		65
Other	106		140
Total Current Liabilities	1,653		1,867
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,429		1,391
Deferred investment tax credits	43		56
Asset retirement obligations	510		497
Other postretirement benefits	205		202
Regulatory liabilities	931		913
Other	189		188
Total Deferred Credits and Other Liabilities	3,307		3,247
Commitments and Contingencies (Note 9)	-		-
Total	$	13,144	$	12,968

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	2011			2010			2011			2010
Operating Revenues:
Electric	$	616		$	575		$	1,174		$	1,115
Gas - regulated	135			137			497			567
Gas - nonregulated	249			227			610			685
Total Operating Revenues	1,000			939			2,281			2,367
Operating Expenses:
Fuel used in electric generation	251			222			462			456
Purchased power	8			3			10			5
Gas purchased for resale	297			277			810			936
Other operation and maintenance	165			167			334			339
Depreciation and amortization	86			83			172			166
Other taxes	51			50			103			98
Total Operating Expenses	858			802			1,891			2,000
Operating Income	142			137			390			367
Other Income (Expense):
Other income	11			14			24			27
Other expenses	(9		)	(9		)	(19		)	(19		)
Interest charges, net of allowance for borrowed funds used during construction of $3, $3, $5 and $5	(70		)	(66		)	(139		)	(131		)
Allowance for equity funds used during construction	5			7			8			10
Total Other Expense	(63		)	(54		)	(126		)	(113		)
Income Before Income Tax Expense	79			83			264			254
Income Tax Expense	23			29			80			74
Income Available to Common Shareholders of SCANA	$	56		$	54		$	184		$	180
Per Common Share Data
Basic Earnings Per Share of Common Stock	$	.44		$	.43		$	1.44		$	1.45
Diluted Earnings Per Share of Common Stock	$	.43		$	.43		$	1.42		$	1.45
Weighted Average Common Shares Outstanding (millions)
Basic	128.5			125.2			128.2			124.5
Diluted	129.7			125.4			129.4			124.6
Dividends Declared Per Share of Common Stock	$	.485		$	.475		$	.97		$	.95

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	2011			2010
Cash Flows From Operating Activities:
Net income	$	184		$	180
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	45			116
Depreciation and amortization	173			174
Amortization of nuclear fuel	14			18
Allowance for equity funds used during construction	(8		)	(10		)
Carrying cost recovery	-			(3		)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	210			100
Inventories	8			30
Prepayments and other	57			(19		)
Regulatory liabilities	(6		)	(3		)
Accounts payable	(93		)	(53		)
Taxes accrued	(63		)	(134		)
Interest accrued	2			1
Regulatory assets	(28		)	(90		)
Changes in other assets	(12		)	(8		)
Changes in other liabilities	(59		)	62
Net Cash Provided From Operating Activities	425			360
Cash Flows From Investing Activities:
Utility property additions and construction expenditures	(466		)	(432		)
Proceeds from investments	10			8
Nonutility property additions	(11		)	(15		)
Purchase of investments	(13		)	(22		)
Settlements of interest rate contracts	(61		)	-
Net Cash Used For Investing Activities	(541		)	(461		)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock	50			106
Proceeds from issuance of long-term debt	796			203
Repayment of long-term debt	(623		)	(67		)
Dividends	(122		)	(117		)
Short-term borrowings, net	126			(104		)
Net Cash Provided From Financing Activities	227			21
Net Increase (Decrease) In Cash and Cash Equivalents	111			(80		)
Cash and Cash Equivalents, January 1	55			162
Cash and Cash Equivalents, June 30	$	166		$	82
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $5 and $5)	$	134		$	132
- Income taxes	-			55
Noncash Investing and Financing Activities:
Accrued construction expenditures	125			95
Capital leases	2			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	2011			2010			2011			2010
Net Income	$	56		$	54		$	184		$	180
Other Comprehensive Income (Loss), net of tax:
Unrealized holding gains (losses) arising during period, net		(15	)		(29	)		(13	)		(40	)
Reclassified to net income:
Losses on cash flow hedging activities		1			4			6			9
Amortization of deferred employee benefit plan costs, net of taxes		-			-			-			1
Comprehensive income attributable to SCANA Corporation (1)	$	42		$	29		$	177		$	150

(1)  Accumulated other comprehensive loss totaled $53.2 million as of June 30, 2011 and $46.6 million as of
December 31, 2010.

See Notes to Condensed Consolidated Financial Statements.

10

SCANA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(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 for the year ended December 31, 2010. 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

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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 utilizing the treasury stock method.  The Company has issued no securities that would have an antidilutive effect on earnings per share.

A reconciliation of the weighted average number of common shares for year to date June 30 for basic and dilutive purposes is as follows:

	Quarterly		Year to Date
In Millions	2011	2010	2011	2010
Weighted Average Shares Outstanding  - Basic	128.5	125.2	128.2	124.5
Net effect of dilutive stock-based compensation plans and equity forward contracts	1.2	0.2	1.2	0.1
Weighted Average Shares - Diluted	129.7	125.4	129.4	124.6

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, 2011, such counterparties held 47% of PSNC Energy’s natural gas inventory, with a carrying value of $18.5 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, 2013.

New Accounting Matter

Effective for the first quarter of 2012, the Company will adopt accounting guidance that revises how comprehensive income is presented in its financial statements.  The Company does not expect the adoption of this guidance to impact results of operations, cash flows or financial position.

11

2.RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G’s retail electric rates are established in part by 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 until May 2011.  SCE&G is allowed to charge and accrue carrying costs monthly on the actual base fuel costs undercollected balance as of the end of each month during this deferral period.  In February 2011, SCE&G requested authorization to increase the cost of fuel component of its retail electric rates to be effective with the first billing cycle of May 2011.  On March 17, 2011, SCE&G, ORS and SCEUC entered into a settlement agreement in which SCE&G agreed to recover its actual base fuel under-collected balance as of April 30, 2011 over a two year period commencing with the first billing cycle of May 2011.  The settlement agreement also provided that SCE&G would be allowed to charge and accrue carrying costs monthly on the deferred balance.  By order dated April 26, 2011, the SCPSC approved the settlement agreement and authorized SCE&G to adjust the cost of fuel component of its retail electric rates effective with the first billing cycle of May 2011.

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 (1) included implementation of an eWNA for SCE&G’s electric customers, which began in August 2010, (2) provided for a $25 million credit, over one year, to SCE&G’s customers to be offset by amortization of weather-related revenues which were deferred in the first quarter of 2010 pursuant to a stipulation between SCE&G and the ORS, (3) provided for a $48.7 million credit to SCE&G’s customers over two years to be offset by accelerated recognition of previously deferred state income tax credits and (4) 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. On July 27, 2010, SCE&G filed the rate rider tariff sheet for DSM Programs with the SCPSC. The tariff rider was applied to bills rendered on or after October 30, 2010. The order requires that SCE&G submit annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentive and net program benefits.  In January 2011, SCE&G submitted to the SCPSC its annual update on DSM Programs.  Included in the filing was a petition to update the rate rider to provide for the recovery of costs, lost net margin revenue, and the approved shared savings incentive for investing in such DSM Programs.  By order dated May 24, 2011, the SCPSC approved the updated rate rider and authorized SCE&G to increase its rates for DSM Programs as set forth in its petition.

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. This initial request, if approved, would result in an annual revenue increase of approximately $5.6 million. On February 26, 2010, the FERC accepted SCE&G’s initial filing and set the filing for hearing and settlement procedures.  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 12, 2011, SCE&G filed a motion to implement interim rates pending FERC action on a full settlement agreement, which the Chief Administrative Law Judge granted on May 13, 2011. On the same day, SCE&G filed a full settlement agreement.  As required by SCE&G’s protocols, on May 16, 2011, SCE&G submitted to the FERC as an informational filing its recalculated Annual Transmission Revenue Requirement or “Annual Update” which conforms to the settlement agreement, effective for the period June 1, 2011 through May 31, 2012.  The settlement agreement was certified as an uncontested settlement on June 30, 2011 and is pending final consideration by FERC.

12

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 the New 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.

In May 2009, two intervenors filed separate appeals of the order 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 reversed the SCPSC’s decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G’s share of the project, as originally approved by the SCPSC, is $4.5 billion in 2007 dollars. Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court’s ruling, however, does not affect the project schedule or disturb the SCPSC’s issuance of a certificate of environmental compatibility and public convenience and necessity, which is required to construct the New Units. On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule that reflects the removal of the contingency reserve and incorporates presently identifiable capital costs of $173.9 million, and by order dated May 16, 2011, the SCPSC approved the updated capital costs schedule as  outlined in the petition.

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. In October 2010, the SCPSC approved an increase of $47.3 million or 2.3%, under the BLRA for the annual revised rates adjustment filing. The new retail electric rates were effective for bills rendered on and after October 30, 2010.  On May 27, 2011, SCE&G filed with the SCPSC its annual request for revised rates under the BLRA seeking authorization to revise its retail electric rates so as to recover the costs of capital associated with the construction of the new nuclear units during the 12 months ended June 30, 2011.  If approved, SCE&G expects this request will constitute a $58.5 million or 2.7% increase to retail electric rates effective for bills rendered on or after October 30, 2011.

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 October 15, 2010, pursuant to the annual RSA filing, the SCPSC approved a decrease in retail natural gas rates of $10.4 million or approximately 2.1%.  The rate adjustment was effective with the first billing cycle of November 2010.  On June 15, 2011, SCE&G filed an application with the SCPSC requesting an increase in retail natural gas rates of $8.64 million or 2.14% under the terms of the RSA.  If approved, the new rates would become effective with the first billing cycle of November 2011.

SCE&G’s natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities. SCE&G’s gas rates are calculated using a methodology which adjusts the cost of gas monthly based on a 12-month rolling average. The annual PGA hearing to review SCE&G’s gas purchasing policies and procedures was conducted in November 2010, before the SCPSC. The SCPSC issued an order in December 2010 finding that SCE&G’s gas purchasing policies and practices during the review period of August 1, 2009, through July 31, 2010, were reasonable and prudent.  The next annual PGA hearing before the SCPSC has been scheduled for November 10, 2011.

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In February 2011, the ORS submitted a request to the SCPSC to suspend SCE&G’s natural gas hedging program.  SCE&G responded in March 2011 indicating no objection to the ORS’s request.  The SCPSC issued an order directing staff to schedule an Oral Argument Information Briefing regarding this matter, which was held in April 2011.  In May 2011, the SCPSC directed its staff to schedule a hearing so that the SCPSC could receive testimony from electric and gas utilities concerning the market for natural gas and the need for natural gas hedging.  In June 2011, the ORS withdrew its petition requesting that the SCPSC suspend SCE&G’s natural gas hedging program.

PSNC Energy

PSNC Energy is subject to a Rider D rate mechanism which allows it to recover from customers all prudently incurred gas costs and certain uncollectible expenses related to gas cost.  The Rider D rate mechanism also allows PSNC Energy to recover, in any manner authorized by the NCUC, losses on negotiated gas and transportation sales.

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 semi-annually for residential and commercial customers based on average per customer consumption.

In October 2010, in connection with PSNC Energy’s 2010 Annual Prudence Review, the NCUC determined that PSNC Energy’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2010.

CGT

On April 29, 2011 CGT filed for a rate increase with the FERC.  The filing was in the form of a settlement agreement negotiated by CGT and its customers.  On July 5, 2011 the FERC approved the settlement agreement with minimal changes. The order approved the new rates to be effective November 1, 2011, as requested.

Regulatory Assets and Regulatory Liabilities

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	2011		2010
Regulatory Assets:
Accumulated deferred income taxes	$	210	$	210
Under-collections - electric fuel adjustment clause	59		25
Environmental remediation costs	31		32
AROs and related funding	310		298
Franchise agreements	42		45
Deferred employee benefit plan costs	321		326
Planned major maintenance	19		6
Deferred losses on interest rate derivatives	90		83
Other	46		36
Total Regulatory Assets	$	1,128	$	1,061
Regulatory Liabilities:
Accumulated deferred income taxes	$	25	$	26
Asset removal costs	804		780
Storm damage reserve	36		38
Monetization of bankruptcy claim	36		37
Deferred gains on interest rate derivatives	25		26
Other	5		6
Total Regulatory Liabilities	$	931	$	913

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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 July 2012 through April 2013.  SCE&G is allowed to accrue interest on the 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 the Company.  These regulatory assets are expected to be recovered over periods of up to approximately 18 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, although recovery periods could become longer at the direction of the SCPSC.

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 pursuant to specific SCPSC orders.  SCE&G collected $8.5 million annually through July 15, 2010, through electric rates, to offset turbine maintenance expenditures.  After July 15, 2010, SCE&G began collecting $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 derivatives 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 approximately 30 years.

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, 2011 and 2010, SCE&G applied costs of $1.8 million and $1.5 million, respectively, to the reserve.  Pursuant to the SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended collection of storm damage reserve funds indefinitely, pending future SCPSC action.

The monetization of bankruptcy claim represents proceeds from the sale of a bankruptcy claim which are expected to be amortized into operating revenue through February 2024.

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The SCPSC, the NCUC or the FERC have reviewed and approved through specific orders most of the items shown as regulatory assets.   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.

3.COMMON EQUITY

SCANA issued common stock valued at $50.1 million (at time of issue) during the six months ended June 30, 2011 through various compensation and dividend reinvestment plans (including the Stock Purchase Savings Plan), including the exercise of approximately 19,600 stock options during the period.  In addition, in May 2010 SCANA entered into forward sale contracts for approximately 6.6 million common shares to be settled no later than February 29, 2012.  There have been no shares issued under the forward sales contracts.

Authorized shares of common stock were 200 million as of June 30, 2011 and 150 million as of December 31, 2010.

4.LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In May 2011, SCE&G issued $100 million of 5.45% first mortgage bonds maturing on February 1, 2041, which constituted a reopening of $250 million of its 5.45% first mortgage bonds issued in January 2011.  Proceeds from these sales were used to retire $150 million of SCE&G first mortgage bonds due February 1, 2011, to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

In February 2011, PSNC Energy issued $150 million of 4.59% unsecured senior notes due February 14, 2021. Proceeds from these notes were used to retire $150 million of medium term notes due February 15, 2011.

In May 2011, SCANA issued $300 million of its 4.75% medium term notes due May 15, 2021.  Proceeds from the sale of these notes were used by SCANA to pay at maturity $300 million of its 6.875% medium term notes.

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.

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						PSNC Energy
		June 30,		December 31,			June 30,			December 31,			June 30,		December 31,
Millions of dollars		2011		2010			2011			2010			2011		2010
Lines of credit:
Committed long-term
Total	$	300		$	300		$	1,100		$	1,100		$	100	$	100
LOC advances		-		-			-			-			-		-
Weighted average interest rate		-		-			-			-			-		-
Outstanding commercial paper (270 or fewer days)	$	71		$	39		$	475		$	381		-		-
Weighted average interest rate		.35	%	.35		%	.35		%	.42		%	-		-
Letters of credit supported by LOC	$	3		$	3		$	.3		$	.3		-		-
Available	$	226		$	258		$	625		$	719		$	100	$	100

SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million, $1.1 billion, of which $400 million relates to Fuel Company, and $100 million, respectively, which expire October 23, 2015.  These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, fossil fuel, and emission and other environmental allowances.  These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10% of the aggregate $1.5 billion credit

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facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%.  Three other banks provide the remaining 6%. These bank credit facilities support the issuance of commercial paper by SCANA, SCE&G (including Fuel Company) and PSNC Energy. 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 SCANA, SCE&G (including Fuel Company) and PSNC Energy.

The Company is obligated with respect to an aggregate of $68.3 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company.  These letters of credit expire, subject to renewal, in the fourth quarter of 2011.

5.INCOME TAXES

In connection with the change in method of accounting for certain repair costs in 2010, the Company identified approximately $36 million of unrecognized tax benefit.  Because this method change is primarily a temporary difference, this additional benefit, if recognized, would not have a significant effect on the effective tax rate.  Within the next 12 months, it is reasonably possible that this unrecognized tax benefit could increase by as much as $12 million or decrease by as much as $36 million.  The events that could cause these changes are direct settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities, or the lapse of an applicable statute of limitation.  No other material changes in the status of the Company’s tax positions have occurred through June 30, 2011.

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  The Company has accrued $0.8 million of interest expense through June 2011.

6.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.

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.  Cash settlement of commodity derivatives are classified as an operating activity in the condensed consolidated statements of cash flows.

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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 recorded 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.  Gains on certain swaps which were terminated prior to maturity of the underlying debt instruments 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 portion of settlement payments made or received upon termination are amortized to interest expense over the term of the underlying debt.  These settlements are classified as an investing activity in the condensed consolidated statements of cash flows.

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, 2011
Cash flow	-	5,524,000	18,671,098	24,195,098
Not designated (a)	10,014,000	-	23,382,436	33,396,436
Total (a)	10,014,000	5,524,000	42,053,534	57,591,534
As of December 31, 2010
Cash flow	-	5,715,000	17,190,351	22,905,351
Not designated (b)	10,677,000	-	20,588,581	31,265,581
Total (b)	10,677,000	5,715,000	37,778,932	54,170,932

(a)  Includes an aggregate  8,019,000 DT related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 6,485,536 DT related to basis swap contracts in Energy Marketing.

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At June 30, 2011 and December 31, 2010, the Company was party to interest rate swaps designated as fair value hedges with an aggregate notional amount of $253.2 million and $556.4 million, respectively, and was party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $572.6 million and $1.1 billion, 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, 2011
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other		$		2	Other current liabilities		$		14
	Other deferred debits		4			Other deferred credits		30
Commodity contracts	Other current liabilities		1			Other current liabilities		3
						Other deferred credits		2
Total			$		7			$		49
Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other		$		3
Energy management contracts	Prepayments and other				4	Other deferred debits		$		1
	Other deferred debits		3			Other current liabilities		4
	Other deferred credits		1			Other deferred credits		3
Total			$		11			$		8
As of December 31, 2010
Derivatives designated as hedging instruments
Interest rate contracts	Other current assets	$		1			Other current liabilities	$	57
	Other deferred debits			7			Other deferred credits		25
Commodity contracts	Other current liabilities	1					Other current liabilities	5
							Other deferred credits	2
Total		$		9				$	89
Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other	$			3
Energy management contracts	Prepayments and other	7					Prepayments and other	$			1
	Other deferred debits	2					Other current liabilities	6
							Other deferred credits	2
Total		$			12			$			9

(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 deferred gains on previously terminated swaps as discussed above, resulted in reductions to interest expense of $1.5 million and $4.0 million for the three and six months ended June 30, 2011, respectively,  and $2.0 million and $5.2 million for the three and six months ended June 30, 2010, respectively.

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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, 2011
Interest rate contracts	$	(15	)	Interest expense	$	-
Six Months Ended June 30,  2011
Interest rate contracts	$	(9	)	Interest expense	$	(1	)
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)
		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, 2011
Interest rate contracts	$	(14	)	Interest expense	$	(1	)
Commodity contracts		(1	)	Gas Purchased for resale		-
Total	$	(15	)		$	(1	)
Six Months Ended June 30, 2011
Interest rate contracts	$	(11	)	Interest expense	$	(2	)
Commodity contracts		(2	)	Gas Purchased for resale		(4	)
Total	$	(13	)		$	(6	)
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)

As of June 30, 2011, 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 $1.4 million as an increase to gas cost and approximately $4.5 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of June 30, 2011, 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	2011			2010
Second Quarter
Commodity contracts	Gas purchased for resale	$	-		$	(1	)
Year to Date
Commodity contracts	Gas purchased for resale	$	(1	)	$	(2	)

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Hedge Ineffectiveness

Other gains (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three and six months ended June 30, 2011 and 2010.

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, 2011 and December 31, 2010, the Company has posted $17.0 million and $20.0 million, respectively, 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, 2011 and December 31, 2010, the Company would be required to post an additional $36.9 million and $74.0 million, respectively, 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, 2011 and December 31, 2010 are $53.9 million and $94.0 million, respectively.

7.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, 2011
Assets -	Available for sale securities	$	3	$	-
	Interest rate contracts		-		6
	Commodity contracts		2		2
	Energy management contracts		-		8
Liabilities -	Interest rate contracts		-		44
	Commodity contracts		1		4
	Energy management contracts		-		8
As of December 31, 2010
Assets -	Available for sale securities	$	3	$	-
	Interest rate contracts		-		8
	Commodity contracts		2		2
	Energy management contracts		-		9
Liabilities -	Interest rate contracts		-		82
	Commodity contracts		1		6
	Energy management contracts		-		11

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, 2011 and December 31, 2010 were as follows:

	June 30, 2011				December 31, 2010
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,664.9	$	5,016.2	$	4,488.3	$	4,840.5

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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.

8.EMPLOYEE BENEFIT PLANS

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	2011			2010			2011		2010
Three months ended June 30,
Service cost	$	4.6		$	4.8		$	1.1	$	1.1
Interest cost	11.1			11.9			3.0		3.2
Expected return on assets	(16.2		)	(16.5		)	-		-
Prior service cost amortization	1.8			1.8			0.3		0.2
Transition obligation amortization	-			-			0.2		0.1
Amortization of actuarial loss	3.0			4.3			0.1		0.1
Net periodic benefit cost	$	4.3		$	6.3		$	4.7	$	4.7
Six months ended June 30,
Service cost	$	9.2		$	9.5		$	2.2	$	2.2
Interest cost	22.2			23.7			6.0		6.2
Expected return on assets	(32.4		)	(32.9		)	-		-
Prior service cost amortization	3.6			3.7			0.6		0.5
Transition obligation amortization	-			-			0.4		0.3
Amortization of actuarial loss	6.0			8.6			0.2		0.2
Net periodic benefit cost	$	8.6		$	12.6		$	9.4	$	9.4

No contribution to the pension trust will be necessary in or for 2011, nor will limitations on benefit payments apply.  Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts  included in the current rates for SCE&G’s retail electric and gas distribution regulated operations.  In connection with the SCPSC’s July 2010 retail electric rate order and November 2010 natural gas RSA order, SCE&G began deferring all pension expense or income related to retail electric and gas operations as a regulatory asset or liability, as applicable.  Costs totaling $2.3 million and $4.6 million were deferred for the three and six months ended June 30, 2011, respectively.  Costs totaling $5.4 million and $10.7 million were deferred for the corresponding periods in 2010.

9.COMMITMENTS AND CONTINGENCIES

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.

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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.

Environmental

SCE&G

In 2005, the EPA issued the CAIR, which required 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.  SCE&G and GENCO 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.  On July 6, 2011 the EPA issued the Cross-State Air Pollution Rule.  This rule replaces CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  The rule requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  The air quality control installations that SCE&G and GENCO have completed should assist the Company in complying with the Cross-State Air Pollution Rule.  The Company will continue to pursue strategies to comply with all applicable environmental regulations.  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 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 and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units.  In March 2011, the EPA proposed new standards for mercury and other specified air pollutants.  The proposed rule provides up to four years for facilities to meet the standards once promulgated.  The EPA is expected to finalize the rule in November 2011.  The proposed rule 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.

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 $8.7 million.  In addition, the National Park Service of the Department of the Interior made a demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina.  In May 2011, the parties agreed to settle for $3.75 million (which amount SCE&G had previously accrued) and are awaiting judicial approval of the settlement.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.  At June 30, 2011, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.6 million and are included in regulatory assets.

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 $3.2 million, which reflects its estimated remaining liability at June 30, 2011. PSNC Energy expects to recover through rates any costs allocable to PSNC Energy arising from the remediation of these sites.

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Nuclear Generation

SCE&G, on behalf of itself and as agent for Santee Cooper has entered into a contractual agreement for the design and construction of two 1,117-MW nuclear generation units at the site of Summer Station.  The contract provides that SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the New 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 will be the operator of the New Units.  SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals $5.5 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 in February 2011 continues to support SCE&G’s need for 55 percent of the output of the two units.  As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units.  Santee Cooper has indicated that it will seek to reduce its 45 percent ownership in the New Units.  Santee Cooper has disclosed that, in March 2011, it entered into a non-binding letter of intent with OUC that may result in the execution of a power purchase agreement with an option for OUC to acquire a portion of Santee Cooper’s ownership interest in the New Units.  Similarly, Santee Cooper announced in July 2011 that it has entered into separate letters of intent with Duke and FMPA that may result in either or both of them acquiring a portion of Santee Cooper’s ownership interest in the New Units.   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.

10.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 and Gas Distribution 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.  Nonreportable segments include a FERC-regulated interstate pipeline company and other companies that conduct nonregulated operations in energy-related and telecommunications industries.

	External			Intersegment			Operating			Income Available to			Segment
Millions of dollars	Revenue			Revenue			Income			Common Shareholders			Assets
Three Months Ended June 30, 2011
Electric Operations	$	616		$	2		$	140			n/a
Gas Distribution		132			-			2			n/a
Retail Gas Marketing		78			-			n/a		$	(3	)
Energy Marketing		172			52			n/a			1
All Other		10			104			3			-
Adjustments/Eliminations		(8	)		(158	)		(3	)		58
Consolidated Total	$	1,000		$	-		$	142		$	56
Six Months Ended June 30, 2011
Electric Operations	$	1,174		$	4		$	262			n/a		$	8,108
Gas Distribution		492			-			86			n/a			2,178
Retail Gas Marketing		280			-			n/a		$	19			178
Energy Marketing		330			97			n/a			2			123
All Other		20			206			8			1			1,287
Adjustments/Eliminations		(15	)		(307	)		34			162			1,270
Consolidated Total	$	2,281		$	-		$	390		$	184		$	13,144

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	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
Retail Gas Marketing		74			-			n/a		$	(5	)
Energy Marketing		153			42			n/a			2
All Other		10			105			5			(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
Retail Gas Marketing		336			-			n/a		$	24			157
Energy Marketing		349			89			n/a			2			116
All Other		18			202			10			(6	)		1,206
Adjustments/Eliminations		(13	)		(295	)		40			160			1,168
Consolidated Total	$	2,367		$	-		$	367		$	180		$	12,252

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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 for the year ended December 31, 2010.

RESULTS OF OPERATIONS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2011

AS COMPARED TO THE CORRESPONDING PERIODS IN 2010

Earnings Per Share

Earnings per share was as follows:

	Second  Quarter				Year to Date
Millions of dollars		2011		2010		2011		2010
Basic earnings per share	$	.44	$	.43	$	1.44	$	1.45
Diluted earnings per share		.43		.43		1.42		1.45

Second Quarter

Basic earnings per share increased by $.06 due to higher electric margin and by $.01 due to lower operating expenses which are explained below.   These increases were partially offset by $.02 due to higher depreciation expense, $.02 due to higher interest expense and by dilution from additional shares outstanding of $.01.

Year to Date

Basic earnings per share decreased by $.10 due to lower gas margin, $.02 due to higher property taxes, $.03 due to higher depreciation expense, $.04 due to higher interest expense and by dilution from additional shares outstanding of $.04.  These decreases were partially offset by $.22 due to higher electric margin and by $.02 due to lower operating expenses which are explained below.

Diluted Earnings Per Share

In May 2010, SCANA entered into equity forward sales contracts for approximately 6.6 million common shares.  During periods when the average market price of SCANA’s common stock is above the per share adjusted forward sales price, the Company computes diluted earnings per share giving effect to this dilutive potential common stock utilizing the treasury stock method.

Dividends Declared

SCANA’s Board of Directors has declared the following dividends on common stock during 2011:

Declaration Date	Dividend Per Share		Record Date	Payment Date
February 11, 2011	$	.485	March 10, 2011	April 1, 2011
April 21, 2011	$	.485	June 10, 2011	July 1, 2011

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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		2011	% Change			2010		2011	% Change			2010
Operating revenues	$	617.7	7.1	%	$	577.0	$	1,178.0	5.3	%	$	1,118.7
Less:  Fuel used in generation		252.2	13.1	%		223.0		464.9	1.3	%		459.0
Purchased power		7.9	*			2.6		10.2	*			5.0
Margin		357.6	1.8	%		351.4	$	702.9	7.4	%	$	654.7

*Greater than 100%

Second Quarter

Margin increased by $15.6 million due to higher SCPSC-approved retail electric base rates in July 2010 and by $10.9 million due to an increase in base rates approved by the SCPSC under the BLRA.  These increases were partially offset by $21.0 million due to lower residential and commercial usage (including the effect of weather).

Year to Date

Margin increased by $31.3 million due to higher SCPSC-approved retail electric base rates in July 2010, by $22.7 million due to an increase in base rates approved by the SCPSC under the BLRA, and by $17.4 million as the result of a 2010 SCPSC regulatory order issued in connection with SCE&G’s annual fuel cost proceeding  (see also discussion at “Income Taxes”).  These increases were partially offset by $24.6 million due to lower residential and commercial usage (including the effect of weather).

Sales volumes (in GWh) related to the electric margin above, by class, were as follows:

	Second Quarter				Year to Date
Classification	2011	% Change		2010	2011	% Change		2010
Residential	2,009	1.4	%	1,981	4,068	(5.0	)%	4,280
Commercial	1,939	(0.1	)%	1,941	3,589	(2.6	)%	3,685
Industrial	1,534	2.7	%	1,493	2,950	3.7	%	2,846
Other	145	1.4	%	143	272	(0.4	)%	273
Total Retail Sales	5,627	1.2	%	5,558	10,879	(1.8	)%	11,084
Wholesale	517	10.5	%	468	998	10.8	%	901
Total Sales	6,144	2.0	%	6,026	11,877	(0.9	)%	11,985

Second Quarter

Retail sales volume increased primarily due to the effects of weather.

Year to Date

Retail sales volume decreased primarily due to the effects of weather in the first quarter.

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	2011		% Change	2010		2011		% Change			2010
Operating revenues	$	132.8	(1.0)%	$	134.1	$	492.6	(12.4	)%	$	562.4
Less:  Gas purchased for resale		70.3	(0.7)%		70.8		285.9	(18.3	)%		350.1
Margin	$	62.5	(1.3)%	$	63.3	$	206.7	(2.6	)%	$	212.3

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Sales volumes (in DT) by class, including transportation, were as follows:

	Second Quarter				Year to Date
Classification (in thousands)	2011	% Change		2010	2011	% Change		2010
Residential	3,091	18.9	%	2,599	23,400	(13.7	)%	27,118
Commercial	4,365	(1.0	)%	4,409	14,715	(8.9	)%	16,151
Industrial	4,347	(8.0	)%	4,727	9,673	-		9,673
Transportation	7,796	2.2	%	7,629	17,369	3.2	%	16,833
Total	19,599	1.2	%	19,364	65,157	(6.6	)%	69,775

Second Quarter

Margin at SCE&G decreased $2.0 million due to the SCPSC-approved decrease in retail gas base rates under the RSA which became effective with the first billing cycle of November 2010.  Margin at PSNC Energy increased by $0.7 million primarily due to residential and commercial customer growth.  Total sales volumes increased primarily due to increased residential customer usage.

Year to Date

Margin at SCE&G decreased $6.3 million due to the SCPSC-approved decrease in retail gas base rates under the RSA which became effective with the first billing cycle of November 2010.  Margin at PSNC Energy increased by $1.5 million primarily due to residential customer growth.  Total sales volumes decreased primarily due to decreased firm customer usage resulting from milder weather.

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		2011		% Change			2010			2011	% Change			2010
Operating revenues	$	77.8		5.3	%	$	73.9		$	280.1	(16.6	)%	$	336.0
Income (loss) available to common shareholders		(2.9	)	(50.8	)%		(5.9	)		18.8	(21.0	)%		23.8

Second Quarter

Changes in operating revenues and income (loss) available to common shareholders are due to higher consumption and lower operating costs.

Year to Date

Changes in operating revenues and income (loss) available to common shareholders are due to milder weather in 2011.

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		2011	% Change			2010		2011	% Change			2010
Operating revenues	$	222.8	14.5	%	$	194.6	$	426.4	(2.6	)%	$	438.0
Income available to common shareholders		1.2	9.1	%		1.1		2.4	50.0	%		1.6

Second Quarter

Operating revenues and income available to common shareholders are higher due to an increase in consumption.

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Year to Date

Operating revenues are lower due to lower market prices.  Income available to common shareholders is higher due to an increase in consumption.

Other Operating Expenses

Other operating expenses were as follows:

	Second Quarter						Year to Date
Millions of dollars		2011	% Change			2010		2011	% Change			2010
Other operation and maintenance	$	164.7	(1.3	)%	$	166.9	$	334.4	(1.3	)%	$	338.9
Depreciation and amortization		86.1	3.7	%		83.0		171.9	3.7	%		165.8
Other taxes		50.8	1.2	%		50.2		102.6	4.9	%		97.8

Second Quarter

Other operation and maintenance expenses decreased by $1.4 million due to lower customer service expenses and general expenses, including bad debt expense, and by $3.3 million due to lower compensation and other benefits.    This decrease was partially offset by $1.8 million due to higher generation, transmission and distribution expenses.  Depreciation and amortization expense increased in 2011 primarily due to net property additions.  Other taxes increased primarily due to higher property taxes.

Year to Date

Other operation and maintenance expenses decreased by $5.4 million due to lower customer service expenses and general expenses, including bad debt expense, and by $1.3 million due to lower compensation and other benefits.  This decrease was partially offset by $2.2 million related to a SCPSC order allowing SCE&G to defer pension expense and income (see also the discussion at “Other Income (Expense)”).   Depreciation and amortization expense increased in 2011 primarily due to net property additions.  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.

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		2011		2010			2011		2010
Income Statement Impact:
Employee benefit costs	$	0.6	$	(0.1	)	$	1.3	$	(0.2	)
Other income		0.2		(0.9	)		0.3		(1.8	)
Balance Sheet Impact:
Capital expenditures		1.0		1.6			1.9		3.2
Component of amount due from Summer Station co-owner		0.3		0.4			0.6		0.8
Regulatory asset		2.3		5.3			4.6		10.6
Total Pension Cost	$	4.4	$	6.3		$	8.7	$	12.6

No contribution to the pension trust will be necessary in or for 2011, nor will limitations on benefit payments apply.  Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts included in rates for its retail electric and gas distribution regulated operations.  In connection with the SCPSC’s July 2010 electric rate order and November 2010 natural gas RSA order, SCE&G began deferring all pension expense and income related to retail electric and gas 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.

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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 related to the construction of two nuclear electric generation units at the site of Summer Station was offset by the decrease in AFC related 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) for the three months ended June 30, 2011 were lower than the same period in 2010 primarily due to lower income before taxes, which excludes the allowance for equity funds used during construction, a nontaxable item, as well as by the recognition of certain previously deferred state income tax credits pursuant to SCE&G’s July 2010 retail electric rate order (see also the discussion at “Electric Operations”).

Year to Date

Income taxes (and the effective tax rate) for the six months ended June 30, 2011 were higher than the same period in 2010 primarily due to higher income before taxes, which excludes the allowance for equity funds used during construction, a nontaxable item, as well as 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, including its $286 million current portion of long-term debt as of June 30, 2011, 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 a future 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 the six and 12 months ended June 30, 2011 was 2.81 and 2.91, respectively.

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						PSNC Energy
		June 30,		December 31,			June 30,			December 31,			June 30,		December 31,
Millions of dollars		2011		2010			2011			2010			2011		2010
Lines of credit:
Committed long-term
Total	$	300		$	300		$	1,100		$	1,100		$	100	$	100
LOC advances		-		-			-			-			-		-
Weighted average interest rate		-		-			-			-			-		-
Outstanding commercial paper (270 or fewer days)	$	71		$	39		$	475		$	381		-		-
Weighted average interest rate		.35	%	.35		%	.35		%	.42		%	-		-
Letters of credit supported by LOC	$	3		$	3		$	.3		$	.3		-		-
Available	$	226		$	258		$	625		$	719		$	100	$	100

SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million, $1.1 billion, of which $400 million relates to Fuel Company, and $100 million, respectively, which expire October 23, 2015.  These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, fossil fuel, and emission and other environmental allowances.  These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National

30

Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10% of the aggregate $1.5 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%.  Three other banks provide the remaining 6%. These bank credit facilities support the issuance of commercial paper by SCANA, SCE&G (including Fuel Company) and PSNC Energy. 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 SCANA, SCE&G (including Fuel Company) and PSNC Energy.

The Company is obligated with respect to an aggregate of $68.3 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company.  These letters of credit expire, subject to renewal, in the fourth quarter of 2011.

At June 30, 2011, the Company had net available liquidity of approximately $1.1 billion.  The Company regularly monitors the commercial paper and short-term credit markets to optimize the timing of repayment of any outstanding balance on its draws, while maintaining appropriate levels of liquidity.  The Company’s long-term debt portfolio has a weighted average maturity of approximately 17 years and bears an average cost of 6.29%.  A significant majority 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.

SCANA issued stock valued at $50.1 million during the six months ended June 30, 2011 through various compensation and dividend reinvestment plans.  In addition, the Company expects to issue approximately 6.6 million common shares under forward sales contracts to be settled no later than February 29, 2012, resulting in net proceeds of approximately $200 million.

The Company’s liquidity is being favorably impacted due to the issuance of final rules by the IRS in late 2010 related to bonus depreciation.  In addition the Company recognizes a cash benefit from the method being used to account for capital maintenance, which results in certain maintenance costs being treated as current expense for income tax purposes.  The Company expects these strategies to generate approximately $60 million of cash flow for 2011.

In May 2011, SCE&G issued $100 million of 5.45% first mortgage bonds maturing on February 1, 2041, which constituted a reopening of $250 million of its 5.45% first mortgage bonds issued in January 2011.  Proceeds from these sales were used to retire $150 million of SCE&G first mortgage bonds due February 1, 2011, to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

In February 2011, PSNC Energy issued $150 million of 4.59% unsecured senior notes due February 14, 2021. Proceeds from these notes were used to retire $150 million of medium term notes due February 15, 2011.

In May 2011 SCANA issued $300 million of its 4.75% medium term notes due May 15, 2021.  Proceeds from the sale of these notes were used by SCANA to pay at maturity $300 million of its 6.875% medium term notes.

The Company paid approximately $61 million in 2011 to settle interest rate contracts associated with the issuance of long-term debt.

OTHER MATTERS

Nuclear Generation

SCE&G, on behalf of itself and as agent for Santee Cooper, has entered into a contractual agreement for the design and construction of two 1,117-MW nuclear generation units at the site of Summer Station.  The contract provides that SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the New 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 will be the operator of the New Units.  SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals $5.5 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.

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SCE&G’s latest Integrated Resource Plan filed with the SCPSC in February 2011 continues to support SCE&G’s need for 55 percent of the output of the two units.  As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units.  Santee Cooper has indicated that it will seek to reduce its 45 percent ownership in the New Units.  Santee Cooper has disclosed that, in March 2011, it entered into a non-binding letter of intent with OUC that may result in the execution of a power purchase agreement with an option for OUC to acquire a portion of Santee Cooper’s ownership interest in the New Units.  Similarly, Santee Cooper announced in July 2011 that it has entered into separate letters of intent with Duke and FMPA that may result in either or both of them acquiring a portion of Santee Cooper’s ownership interest in the New Units.   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.

In March 2011, a tsunami resulting from a massive earthquake severely damaged several nuclear generating units and their back-up cooling systems in Japan.  The impact of the disaster is being evaluated world-wide, and numerous political and regulatory bodies, including those in the United States, are seeking to determine if additional safety measures should be required at other existing nuclear facilities, as well as those planned for construction.  In particular, on July 12, 2011, the NRC’s Near-Term Task Force issued a report titled “Recommendations for Enhancing Reactor Safety in the 21st Century,” which SCE&G is evaluating.  SCE&G cannot predict what regulatory or other outcomes may be implemented in the United States, nor how such initiatives would impact SCE&G’s existing Summer Station or the licensing, construction or operation of the New Units.

In April 2011, the NRC and the USACE completed the FEIS for the New Units, concluding that there were no environmental impacts that would preclude issuing the COL for the New Units.  The NRC continues to compile its final safety evaluation report, which is expected to be completed in the summer of 2011.

Fuel Contract

On January 27, 2011, SCE&G, for itself and as agent for Santee Cooper, and Westinghouse entered into a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, Westinghouse will supply enriched nuclear fuel assemblies for Summer Station Unit 1 and the New Units. Westinghouse will be SCE&G’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements of Summer Station Unit 1 and the New Units through 2033. SCE&G is dependent upon Westinghouse for providing fuel assemblies for the new AP1000 passive reactors in the New Units in the current and anticipated future absence of other commercially viable sources. Westinghouse currently provides maintenance and engineering support to Summer Station Unit 1 under a services alliance arrangement, and SCE&G has also contracted for Westinghouse to provide similar support services to the New Units upon their completion and commencement of commercial operation in 2016 and 2019, respectively.

Air Quality

SCE&G

In 2005, the EPA issued the CAIR, which required 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.  SCE&G and GENCO 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.  On July 6, 2011 the EPA issued the Cross-State Air Pollution Rule.  This rule replaces CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  The rule requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  The air quality control installations that SCE&G and GENCO have completed should assist the Company in complying with the Cross-State Air Pollution Rule.  The Company will continue to pursue strategies to comply with all applicable environmental regulations.  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.

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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 and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units.  In March 2011, EPA proposed new standards for mercury and other specified air pollutants.  The proposed rule provides up to four years for facilities to meet the standards once promulgated.  The EPA is expected to finalize the rule in November 2011.  The proposed rule 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.

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 $8.7 million.  In addition, the National Park Service of the Department of the Interior made a demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina.  In May 2011, the parties agreed to settle for $3.75 million (which amount SCE&G had previously accrued) and are awaiting judicial approval of the settlement.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.  At June 30, 2011, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.6 million and are included in regulatory assets.

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 $3.2 million, which reflects its estimated remaining liability at June 30, 2011. PSNC Energy expects to recover through rates any costs allocable to PSNC Energy arising from the remediation of these sites.

For additional information related to environmental matters and claims and litigation, see Note 9 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 for the year ended December 31, 2010.  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 4 and 6 of the condensed consolidated financial statements.

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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 6 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 DT.  Fair value represents quoted market prices for these or similar instruments.

Expected Maturity:
Futures Contracts		Options
			Purchased Call
2011	Long	2011	(Long)
Settlement Price (a)	4.52	Strike Price (a)	5.11
Contract Amount (b)	14.3	Contract Amount (b)	26.0
Fair Value (b)	13.8	Fair Value (b)	0.8
2012		2012
Settlement Price (a)	4.81	Strike Price (a)	5.10
Contract Amount (b)	8.9	Contract Amount (b)	25.1
Fair Value (b)	8.7	Fair Value (b)	1.6
(a)Weighted average, in dollars
(b)Millions of dollars

Swaps	2011	2012	2013	2014	2015	2016
Commodity Swaps:
Pay fixed/receive variable (b)	31.6	37.6	18.5	7.9	7.9	1.4
Average pay rate (a)	5.1017	5.4586	5.8027	5.4729	5.4729	5.6850
Average received rate (a)	4.5313	4.8261	5.1582	5.4162	5.6976	5.9752
Fair value (b)	28.0	33.2	16.4	7.8	8.2	1.4
Pay variable/receive fixed (b)	22.3	22.6	13.8	7.5	7.9	1.4
Average pay rate (a)	4.6055	4.8688	5.0989	5.2266	5.4546	5.7287
Average received rate (a)	5.0475	5.4298	5.4628	5.4850	5.4850	5.6950
Fair value (b)	24.5	25.2	14.8	7.9	7.9	1.4
Basis Swaps:
Pay variable/receive variable (b)	13.6	20.3	4.4
Average pay rate (a)	4.5129	4.8465	5.2625
Average received rate (a)	4.5058	4.8325	5.2143
Fair value (b)	13.6	20.2	4.3
(a) Weighted average, in dollars
(b) Millions of dollars

ITEM 4. CONTROLS AND PROCEDURES

As of June 30, 2011, 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, 2011, 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, 2011 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

35

ITEM 1. FINANCIAL STATEMENTS

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,			December 31,
Millions of dollars	2011			2010
Assets
Utility Plant In Service	$	10,244		$	10,112
Accumulated Depreciation and Amortization	(3,188		)	(3,098		)
Construction Work in Progress	1,269			1,051
Nuclear Fuel, Net of Accumulated Amortization	133			133
Utility Plant, Net ($630 and $634 related to VIEs)	8,458			8,198
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	51			46
Assets held in trust, net - nuclear decommissioning	80			76
Other investments	4			4
Nonutility Property and Investments, Net	135			126
Current Assets:
Cash and cash equivalents	28			31
Receivables, net of allowance for uncollectible accounts of $3 and $3	444			507
Inventories (at average cost):
Fuel and gas supply	192			216
Materials and supplies	118			117
Emission allowances	4			6
Prepayments and other	121			168
Deferred income taxes	15			15
Total Current Assets ($203 and $221 related to VIEs)	922			1,060
Deferred Debits and Other Assets:
Pension asset	59			57
Regulatory assets	1,065			996
Other	136			137
Total Deferred Debits and Other Assets ($42 and $43 related to VIEs)	1,260			1,190
Total	$	10,775		$	10,574

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	June 30,		December 31,
Millions of dollars	2011		2010
Capitalization and Liabilities
Common equity	$	3,516	$	3,436
Noncontrolling interest	106		105
Long-Term Debt, net	3,227		3,037
Total Capitalization	6,849		6,578
Current Liabilities:
Short-term borrowings	475		381
Current portion of long-term debt	22		22
Accounts Payable	229		341
Affiliated Payables	145		140
Customer deposits and customer prepayments	57		60
Taxes accrued	78		137
Interest accrued	54		50
Dividends declared	49		54
Derivative financial instruments	-		34
Other	59		80
Total Current Liabilities	1,168		1,299
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,276		1,240
Deferred investment tax credits	42		56
Asset retirement obligations	490		478
Other postretirement benefits	163		163
Regulatory liabilities	675		662
Other	112		98
Total Deferred Credits and Other Liabilities	2,758		2,697
Commitments and Contingencies (Note 9)	-		-
Total	$	10,775	$	10,574

See Notes to Condensed Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Millions of dollars	2011			2010			2011			2010
Operating Revenues:
Electric	$	618		$	577		$	1,178		$	1,119
Gas	73			75			218			255
Total Operating Revenues	691			652			1,396			1,374
Operating Expenses:
Fuel used in electric generation	252			223			465			459
Purchased power	8			3			10			5
Gas purchased for resale	49			48			136			167
Other operation and maintenance	127			128			260			260
Depreciation and amortization	71			66			142			133
Other taxes	47			46			94			89
Total Operating Expenses	554			514			1,107			1 ,113
Operating Income	137			138			289			261
Other Income (Expense):
Other income	1			3			2			7
Other expenses	(3		)	(4		)	(7		)	(7		)
Interest charges, net of allowance for borrowed funds used during construction of $3, $3, $4 and $5	(50		)	(46		)	(100		)	(93		)
Allowance for equity funds used during construction	5			7			8			10
Total Other Expense	(47		)	(40		)	(97		)	(83		)
Income Before Income Tax Expense	90			98			192			178
Income Tax Expense	29			35			60			51
Net Income	61			63			132			127
Less Net Income Attributable to Noncontrolling Interest	2			3			5			5
Earnings Available to Common Shareholder	$	59		$	60		$	127		$	122
Dividends Declared on Common Stock	$	49		$	47		$	100		$	94

See Notes to Condensed Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
Millions of dollars	2011			2010
Cash Flows From Operating Activities:
Net income	$	132		$	127
Adjustments to reconcile net income to net cash provided from operating activities:
Earnings from equity method investments, net of distribution	1			1
Deferred income taxes, net	36			115
Depreciation and amortization	142			140
Amortization of nuclear fuel	14			18
Allowance for equity funds used during construction	(8		)	(10		)
Carrying cost recovery	-			(3		)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	63			(11		)
Inventories	3			7
Prepayments and other	43			(9		)
Regulatory assets	(30		)	(91		)
Regulatory liabilities	(4		)	(2		)
Accounts payable	(46		)	(19		)
Taxes accrued	(59		)	(127		)
Interest accrued	4			(1		)
Changes in other assets	(8		)	(4		)
Changes in other liabilities	(46		)	79
Net Cash Provided From Operating Activities	237			210
Cash Flows From Investing Activities:
Utility property additions and construction expenditures	(421		)	(396		)
Proceeds from investments	4			8
Nonutility property additions	(4		)	(1		)
Investment in affiliate	-			41
Purchase of investments	(3		)	(12		)
Settlements of interest rate contracts	(31		)	-
Net Cash Used For Investing Activities	(455		)	(360		)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	349			51
Repayment of long-term debt	(164		)	(11		)
Dividends	(104		)	(97		)
Contributions from parent	49			105
Short-term borrowings –affiliate, net	(9		)	12
Short-term borrowings, net	94			(23		)
Net Cash Provided From (Used For) Financing Activities	215			37
Net Decrease In Cash and Cash Equivalents	(3		)	(113		)
Cash and Cash Equivalents, January 1	31			134
Cash and Cash Equivalents, June 30	$	28		$	21
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $4 and $5)	$	87		$	87
- Income taxes	-			31
Noncash Investing and Financing Activities:
Accrued construction expenditures	116			89
Capital leases	2			-

See Notes to Condensed Consolidated Financial Statements.

39

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	2011			2010			2011			2010
Net Income	$	61		$	63		$	132		$	127
Other Comprehensive Income, net of tax:
Reclassification to net income - amortization of deferred employee benefit plan costs, net of taxes	-			-			-			1
Total Comprehensive Income	61			63			132			128
Less comprehensive income attributable to noncontrolling interest	(2		)	(3		)	(5		)	(5		)
Comprehensive income available to common shareholder (1)	$	59		$	60		$	127		$	123

(1)  Accumulated other comprehensive loss totaled $2.6 million as of June 30, 2011 and $2.7 million as
of December 31, 2010.

See Notes to Condensed Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(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 for the year ended December 31, 2010.  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

Variable Interest Entity

SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs), 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, SCE&G’s parent. 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 605 MW net generating capacity (summer rating). GENCO’s electricity is sold solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $496 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and emission allowances. See also Note 4.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

New Accounting Matter

Effective for the first quarter of 2012, Consolidated SCE&G will adopt accounting guidance that revises how comprehensive income is presented in its financial statements.  Consolidated SCE&G does not expect the adoption of this guidance to impact results of operations, cash flows or financial position.

2.RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G’s retail electric rates are established in part, by 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 until May 2011.  SCE&G is allowed to charge and accrue carrying costs monthly on the actual base fuel costs undercollected balance as of the end of each month during this deferral period.  In February 2011, SCE&G requested authorization to increase the cost of fuel component of its retail electric rates to be effective with the first billing cycle of May 2011.  On March 17, 2011, SCE&G, ORS and SCEUC entered into a settlement agreement in which SCE&G agreed to recover its actual base fuel under-collected balance as of April 30, 2011 over a two year period commencing with the first billing cycle of May 2011.  The settlement

41

agreement also provided that SCE&G would be allowed to charge and accrue carrying costs monthly on the deferred balance.  By order dated April 26, 2011, the SCPSC approved the settlement agreement and authorized SCE&G to adjust the cost of fuel component of its retail electric rates effective with the first billing cycle of May 2011.

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 (1) included implementation of an eWNA for SCE&G’s electric customers, which began in August 2010, (2) provided for a $25 million credit, over one year, to SCE&G’s customers to be offset by amortization of weather-related revenues which were deferred in the first quarter of 2010 pursuant to a stipulation between SCE&G and the ORS, (3) provided for a $48.7 million credit to SCE&G’s customers over two years to be offset by accelerated recognition of previously deferred state income tax credits and (4) 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. On July 27, 2010, SCE&G filed the rate rider tariff sheet for DSM Programs with the SCPSC. The tariff rider was applied to bills rendered on or after October 30, 2010. The order requires that SCE&G submit annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentive and net program benefits.  In January 2011, SCE&G submitted to the SCPSC its annual update on DSM Programs.  Included in the filing was a petition to update the rate rider to provide for the recovery of costs, lost net margin revenue, and the approved shared savings incentive for investing in such DSM Programs.  By order dated May 24, 2011, the SCPSC approved the updated rate rider and authorized SCE&G to increase its rates for DSM Programs as set forth in its petition.

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. This initial request, if approved, would result in an annual revenue increase of approximately $5.6 million. On February 26, 2010, the FERC accepted SCE&G’s initial filing and set the filing for hearing and settlement procedures.  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 12, 2011, SCE&G filed a motion to implement interim rates pending FERC action on a full settlement agreement, which the Chief Administrative Law Judge granted on May 13, 2011. On the same day, SCE&G filed a full settlement agreement.  As required by SCE&G’s protocols, on May 16, 2011, SCE&G submitted to the FERC as an informational filing its recalculated Annual Transmission Revenue Requirement or “Annual Update” which conforms to the settlement agreement, effective for the period June 1, 2011 through May 31, 2012.  The settlement agreement was certified as an uncontested settlement on June 30, 2011 and is pending final consideration by FERC.

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 the New 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.

In May 2009, two intervenors filed separate appeals of the order 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 reversed the SCPSC’s decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G’s share of the project, as originally approved by the SCPSC, is $4.5 billion in 2007 dollars.  Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the

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recovery of any additional capital costs.  The Court’s ruling, however, does not affect the project schedule or disturb the SCPSC’s issuance of a certificate of environmental compatibility and public convenience and necessity, which is required to construct the New Units.  On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule that reflects the removal of the contingency reserve and incorporates presently identifiable capital costs of $173.9 million, and by order dated May 16, 2011, the SCPSC approved the updated capital costs schedule as outlined in the petition.

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. In October 2010, the SCPSC approved an increase of $47.3 million or 2.3%, under the BLRA for the annual revised rates adjustment filing.  The new retail electric rates were effective for bills rendered on and after October 30, 2010.  On May 27, 2011, SCE&G filed with the SCPSC its annual request for revised rates under the BLRA seeking authorization to revise its retail electric rates so as to recover the costs of capital associated with the construction of the new nuclear units during the 12 months ended June 30, 2011.  If approved, SCE&G expects this request will constitute a $58.5 million of 2.7% increase to retail electric rates effective for bills rendered on and after October 30, 2011.

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 October 15, 2010, pursuant to the annual RSA filing, the SCPSC approved a decrease in retail natural gas rates of $10.4 million or approximately 2.1%.  The rate adjustment was effective with the first billing cycle of November 2010.  On June 15, 2011, SCE&G filed an application with the SCPSC requesting an increase in retail natural gas rates of $8.64 million or 2.14% under the terms of the RSA.  If approved, the new rates would become effective with the first billing cycle of November 2011.

SCE&G’s natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities. SCE&G’s gas rates are calculated using a methodology which adjusts the cost of gas monthly based on a 12-month rolling average. The annual PGA hearing to review SCE&G’s gas purchasing policies and procedures was conducted in November 2010, before the SCPSC. The SCPSC issued an order in December 2010 finding that SCE&G’s gas purchasing policies and practices during the review period of August 1, 2009, through July 31, 2010, were reasonable and prudent.  The next annual PGA hearing before the SCPSC has been scheduled for November 10, 2011.

In February 2011, the ORS submitted a request to the SCPSC to suspend SCE&G’s natural gas hedging program.  SCE&G responded in March 2011 indicating no objection to the ORS’s request.  The SCPSC issued an order directing staff to schedule an Oral Argument Information Briefing regarding this matter, which was held in April 2011.  In May 2011, the SCPSC directed its staff to schedule a hearing so that the SCPSC could receive testimony from electric and gas utilities concerning the market for natural gas and the need for natural gas hedging.  In June 2011, the ORS withdrew its petition requesting that the SCPSC suspend SCE&G’s natural gas hedging program.

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Regulatory Assets and Regulatory Liabilities

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	2011		2010
Regulatory Assets:
Accumulated deferred income taxes	$	205	$	205
Under collections – electric fuel adjustment clause	59		25
Environmental remediation costs	26		27
AROs and related funding	296		284
Franchise agreements	42		45
Deferred employee benefit plan costs	285		288
Planned major maintenance	19		6
Deferred losses on interest rate derivatives	90		83
Other	43		33
Total Regulatory Assets	$	1,065	$	996

Regulatory Liabilities:
Accumulated deferred income taxes	$	24	$	26
Asset removal costs	585		568
Storm damage reserve	36		38
Deferred gains on interest rate derivatives	25		26
Other	5		4
Total Regulatory Liabilities	$	675	$	662

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 July 2012 through April 2013.  SCE&G is allowed to accrue interest on the 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 18 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, although recovery periods could become longer at the direction of the SCPSC.

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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 pursuant to specific SCPSC orders.  SCE&G collected $8.5 million annually through July 15, 2010, through electric rates, to offset turbine maintenance expenditures.  After July 15, 2010, SCE&G began collecting $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 derivatives 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 approximately 30 years.

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, 2011 and 2010, SCE&G applied costs of $1.8 million and $1.5 million, respectively, to the reserve.  Pursuant to the SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended collection of the storm damage reserve indefinitely, pending future SCPSC action.

The SCPSC or the FERC have reviewed and approved through specific orders most of the items shown as regulatory assets.   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.

3.COMMON EQUITY

Changes in common equity during the six months ended June 30, 2011 and 2010 were as follows:

Millions of dollars	Common Equity			Noncontrolling Interest			Total Equity
Balance at January 1, 2011	$	3,436		$	105		$	3,541
Capital contribution from parent	49			-			49
Dividends declared	(96		)	(4		)	(100		)
Comprehensive income	127			5			132
Balance as of June 30, 2011	$	3,516		$	106		$	3,622

Balance at January 1, 2010	$	3,162		$	97		$	3,259
Capital contribution from parent	105			-			105
Dividends declared	(91		)	(3		)	(94		)
Comprehensive income	122			5			127
Balance as of June 30, 2010	$	3,298		$	99		$	3,397

Authorized shares of common stock were 50 million as of June 30, 2011 and December 31, 2010.

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4.LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In May 2011, SCE&G issued $100 million of 5.45% first mortgage bonds maturing on February 1, 2041, which constituted a reopening of $250 million of its 5.45% first mortgage bonds issued in January 2011.  Proceeds from these sales were used to retire $150 million of SCE&G first mortgage bonds due February 1, 2011, to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

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.

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
	June 30,			December 31,
Millions of dollars	2011			2010
Lines of credit:
Committed long-term
Total	$	1,100		$	1,100
LOC advances	-			-
Weighted average interest rate	-			-
Outstanding commercial paper (270 or fewer days)	$	475		$	381
Weighted average interest rate	.35		%	.42		%
Letters of credit supported by LOC	$	.3		$	.3
Available	$	625		$	719

SCE&G and Fuel Company are parties to five-year credit agreements in the amount of $1.1 billion, of which $400 million relates to Fuel Company, which expire October 23, 2015.  These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, fossil fuel, and emission and other environmental allowances.  These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10% of the aggregate $1.1 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%.  Three other banks provide the remaining 6%. 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).

Consolidated SCE&G is obligated with respect to an aggregate of $68.3 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company.  These letters of credit expire, subject to renewal, in the fourth quarter of 2011.

5.INCOME TAXES

In connection with the change in method of accounting for certain repair costs in 2010, Consolidated SCE&G identified approximately $36 million of unrecognized tax benefit.  Because this method change is primarily a temporary difference, this additional benefit, if recognized, would not have a significant effect on the effective tax rate.  Within the next 12 months, it is reasonably possible that this unrecognized tax benefit could increase by as much as $12 million or decrease by as much as $36 million.  The events that could cause these changes are direct settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities, or the lapse of an applicable statute of limitation.  No other material changes in the status of Consolidated SCE&G’s tax positions have occurred through June 30, 2011.

Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  Consolidated SCE&G has accrued $0.8 million of interest expense through June 2011.

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6.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 the 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.  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.  Cash settlement of commodity derivatives are classified as an operating activity in the condensed consolidated statements of cash flows.

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 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 portion of settlement payments made or received upon termination are amortized to interest expense over the term of the underlying debt.  These settlements are classified as an investing activity in the condensed consolidated statements of cash flows.

Quantitative Disclosures Related to Derivatives

SCE&G was party to natural gas derivative contracts for 2,420,000 DT at June 30, 2011 and 2,460,000 DT at December 31, 2010.  Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $221.4 million at June 30, 2011 and $421.4 million at December 31, 2010.

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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 (a)	Value		Location (a)	Value
As of June 30, 2011
Derivatives designated as hedging instruments
Interest rate contracts	Other deferred debits	$	3	Other deferred credits	$	12
Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other	$	1
As of December 31, 2010
Derivatives designated as hedging instruments
Interest rate contracts	Other deferred debits	$	4	Other current liabilities	$	34
				Other deferred credits	1
Total		$	4		$	35
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 with the same counterparty are reported as either a net asset or liability.

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

				Gain (Loss) Reclassified from
Derivatives in Cash Flow	Gain (Loss) Deferred			Deferred Accounts into Income
Hedging Relationships	in Regulatory Accounts			(Effective Portion)
Millions of dollars	(Effective Portion)			Location	Amount
Three Months Ended June 30, 2011
Interest rate contracts	$	(15	)	Interest expense	$	-
Six Months Ended June 30, 2011
Interest rate contracts	$	(9	)	Interest expense	$	(1	)
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	)

	Gain (Loss) Recognized in Income
Derivatives Not Designated as
Hedging Instruments
Millions of dollars	Location	2011			2010
Second Quarter
Commodity contracts	Gas purchased for resale	$	-		$	(1	)
Year to Date
Commodity contracts	Gas purchased for resale	$	(1	)	$	(2	)

Hedge Ineffectiveness

Other gains (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three and six months ended June 30, 2011 and 2010.

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Credit Risk Considerations

Certain of Consolidated SCE&G’s derivative instruments contain contingent provisions that require collateral to be provided upon the occurrence of specific events, primarily credit downgrades.  As of June 30, 2011 and December 31, 2010, Consolidated SCE&G has posted no collateral, respectively, 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, 2011 and December 31, 2010, Consolidated SCE&G would be required to post $11.6 million and $34.9 million, respectively, 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, 2011 and December 31, 2010 is $11.6 million and $34.9 million, respectively.

7.FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

SCE&G values commodity derivative assets and liabilities using unadjusted NYMEX prices to determine fair value, 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, 2011
Assets -	Interest rate contracts	$	-	$	3
	Commodity contracts		1		-
Liabilities-	Interest rate contracts		-		12
As of December 31, 2010
Assets -	Interest rate contracts	$	-	$	4
	Commodity contracts		1		-
Liabilities -	Interest rate contracts		-		35

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, 2011 and December 31, 2010 were as follows:

	June 30, 2011				December 31, 2010
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,249.4	$	3,517.0	$	3,059.7	$	3,321.8

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.

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8.EMPLOYEE BENEFIT PLANS

Pension and Other Postretirement Benefit Plans

Consolidated SCE&G participates in SCANA’s noncontributory defined benefit pension plan, which covers substantially all regular, full-time employees, and also participates in SCANA’s unfunded postretirement health care and life insurance programs, which provide benefits to active and retired employees.  Components of net periodic benefit cost recorded by Consolidated SCE&G were as follows:

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2011			2010			2011		2010
Three months ended June 30,
Service cost	$	3.7		$	3.5		$	0.9	$	0.9
Interest cost	9.5			10.2			2.3		2.4
Expected return on assets	(13.7		)	(14.5		)	-		-
Prior service cost amortization	1.5			1.6			0.2		0.2
Amortization of actuarial loss	2.5			4.2			0.1		-
Net periodic benefit cost	$	3.5		$	5.0		$	3.5	$	3.5
Six months ended June 30,
Service cost	$	7.4		$	7.1		$	1.8	$	1.7
Interest cost	18.9			20.4			4.7		4.8
Expected return on assets	(27.5		)	(29.0		)	-		-
Prior service cost amortization	3.0			3.3			0.4		0.4
Amortization of actuarial loss	5.1			8.4			0.1		0.1
Net periodic benefit cost	$	6.9		$	10.2		$	7.0	$	7.0

No contribution to the pension trust will be necessary in or for 2011, nor will limitations on benefit payments apply.  Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts included in current rates for SCE&G’s retail electric and gas distribution regulated operations.  In connection with the SCPSC’s July 2010 retail electric rate order and November 2010 natural gas RSA order, SCE&G began deferring all pension expense or income related to retail electric and gas operations as a regulatory asset or liability, as applicable.  Costs totaling $2.3 million and $4.6 million were deferred for the three and six months ended June 30, 2011, respectively.  Costs totaling $5.4 million and $10.7 million were deferred for the corresponding periods in 2010.

9.COMMITMENTS AND CONTINGENCIES

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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Environmental

In 2005, the EPA issued the CAIR, which required 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.  SCE&G and GENCO 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.  On July 6, 2011 the EPA issued the Cross-State Air Pollution Rule.  This rule replaces CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  The rule requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  The air quality control installations that SCE&G and GENCO have completed should assist Consolidated SCE&G in complying with the Cross-State Air Pollution Rule.  Consolidated SCE&G will continue to pursue strategies to comply with all applicable environmental regulations.  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 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 and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units.  In March 2011, the EPA proposed new standards for mercury and other specified air pollutants.  The proposed rule provides up to four years for facilities to meet the standards once promulgated.  The EPA is expected to finalize the rule in November 2011.  The proposed rule 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.

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 $8.7 million.  In addition, the National Park Service of the Department of the Interior made a demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina.  In May 2011, the parties agreed to settle for $3.75 million (which amount SCE&G had previously accrued) and are awaiting judicial approval of the settlement.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.  At June 30, 2011, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.6 million and are included in regulatory assets.

Nuclear Generation

SCE&G, on behalf of itself and as agent for Santee Cooper has entered into a contractual agreement for the design and construction of two 1,117-MW nuclear generation units at the site of Summer Station.  The contract provides that SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the New 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 will be the operator of the New Units.  SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals $5.5 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 in February 2011 continues to support SCE&G’s need for 55 percent of the output of the two units.  As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units.  Santee Cooper has indicated that it will seek to reduce its 45 percent ownership in the New Units.  Santee Cooper has disclosed that, in March 2011, it entered into a non-binding letter of intent with OUC that may result in the execution of a power purchase agreement with an option for OUC to acquire a portion of Santee Cooper’s

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ownership interest in the New Units.  Similarly, Santee Cooper announced in July 2011 that it has entered into separate letters of intent with Duke and FMPA that may result in either or both of them acquiring a portion of Santee Cooper’s ownership interest in the New Units.  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.

10.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 $2.1 million payable to CGT for transportation services at June 30, 2011 and December 31, 2010, 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 $96.7 million and $89.0 million for the six months ended June 30, 2011 and 2010, respectively.  SCE&G’s payables to SEMI for such purposes were $17.4 million and $16.1 million as of June 30, 2011 and December 31, 2010, 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 accounts for these investments using the equity method.  SCE&G’s receivables from these affiliates were $16.9 million at June 30, 2011 and insignificant at December 31, 2010.  SCE&G’s payables to these affiliates were $17.0 million at June 30, 2011 and insignificant at December 31, 2010.  SCE&G’s total purchases were $53.3 million and $40.8 million for the six months ended June 30, 2011 and 2010, respectively.  SCE&G’s total sales were $53.1 million and $40.4 million for the six months ended June 30, 2011 and 2010, respectively.

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 expense from money pool transactions was not significant for the six months ended June 30, 2011 or 2010.  At June 30, 2011 and December 31, 2010, Consolidated SCE&G owed an affiliate $62.5 million and $71.0 million, respectively.

11.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.

			Operating			Earnings Available
	External		Income			to Common		Segment
Millions of Dollars	Revenue		(Loss)			Shareholder		Assets
Three Months Ended June 30, 2011
Electric Operations	$	618	$	140		n/a
Gas Distribution	73		(2		)	n/a
Adjustments/Eliminations	-		(1		)	$	59
Consolidated Total	$	691	$	137		$	59
Six Months Ended June 30, 2011
Electric Operations	$	1,178	$	262		n/a		$	8,107
Gas Distribution	218		28			n/a		597
Adjustments/Eliminations	-		(1		)	$	127	2,071
Consolidated Total	$	1,396	$	289		$	127	$	10,775
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

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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

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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 for the year ended December 31, 2010.

RESULTS OF OPERATIONS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2011

AS COMPARED TO THE CORRESPONDING PERIOD IN 2010

Net Income

Net income for Consolidated SCE&G was as follows:

	Second Quarter					Year to Date
Millions of dollars	2011		% Change	2010		2011		% Change	2010
Net income	$	61.4	(2.1)%	$	62.7	$	132.0	4.3%	$	126.5

Second Quarter

Net income decreased by $1.0 million due to lower gas margin, higher depreciation expense of $2.1 million and higher interest expense of $2.7 million.  These decreases were partially offset by higher electric margin of $3.8 million.

Year to Date

Net income increased by higher electric margin of $19.1 million.  This increase was partially offset by $4.4 million due to lower gas margin, higher operation and maintenance expenses of $1.4 million, higher depreciation expense of $4.2 million, higher property taxes of $2.7 million and higher interest expense of $4.3 million.

Dividends Declared

Consolidated SCE&G’s Boards of Directors declared the following dividends on common stock (all of which was held by SCANA) during 2011:

Declaration Date	Amount	Quarter Ended	Payment Date
February 11, 2011	$50.6 million	March 31, 2011	April 1, 2011
April 21, 2011	49.0 million	June 30, 2011	July 1, 2011

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	2011		% Change	2010		2011		% Change	2010
Operating revenues	$	617.7	7.1%	$	577.0	$	1,178.0	5.3%	$	1,118.7
Less: Fuel used in electric generation	252.2		13.1%	223.0		464.9		1.3%	459.0
Purchased power	7.9		*	2.6		10.2		*	5.0
Margin	$	357.6	1.8%	$	351.4	$	702.9	7.4%	$	654.7

*Greater than 100%

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Second Quarter

Margin increased by $15.6 million due to higher SCPSC-approved retail electric base rates in July 2010 and by $10.9 million due to an increase in base rates approved by the SCPSC under the BLRA.  These increases were partially offset by $21.0 million due to lower residential and commercial usage (including the effect of weather).

Year to Date

Margin increased by $31.3 million due to higher SCPSC-approved retail electric base rates in July 2010, by $22.7 million due to an increase in base rates approved by the SCPSC under the BLRA, and by $17.4 million as the result of a 2010 SCPSC regulatory order issued in connection with SCE&G’s annual fuel cost proceeding see also discussion at “Income Taxes”).  These increases were partially offset by $24.6 million due to lower residential and commercial usage (including the effect of weather).

Sales volumes (in GWh) related to the electric margin above, by class, were as follows:

	Second Quarter			Year to Date
Classification	2011	% Change	2010	2011	% Change	2010
Residential	2,009	1.4%	1,981	4,068	(5.0)%	4,280
Commercial	1,939	(0.1)%	1,941	3,589	(2.6)%	3,685
Industrial	1,534	2.7%	1,493	2,950	3.7%	2,846
Other	145	1.4%	143	272	(0.4)%	273
Total Retail Sales	5,627	1.2%	5,558	10,879	(1.8)%	11,084
Wholesale	517	10.5%	468	998	10.8%	901
Total Sales	6,144	2.0%	6,026	11,877	(0.9)%	11,985

Second Quarter

Retail sales volume increased primarily due to the effects of weather.

Year to Date

Retail sales volume decreased primarily due to the effects of weather in the first quarter.

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	2011		% Change	2010		2011		% Change	2010
Operating revenues	$	73.4	(1.3)%	$	74.4	$	217.5	(14.7)%	$	255.0
Less: Gas purchased for resale	48.5		1.3%	47.9		136.3		(18.2)%	166.7
Margin	$	24.9	(6.0)%	$	26.5	$	81.2	(8.0)%	$	88.3

Sales volumes (in DT) by class, including transportation, were as follows:

	Second Quarter			Year to Date
Classification (in thousands)	2011	% Change	2010	2011	% Change	2010
Residential	973	11.5%	873	7,505	(18.3)%	9,182
Commercial	2,380	(4.4)%	2,489	6,657	(8.6)%	7,286
Industrial	4,021	(3.6)%	4,170	8,488	3.8%	8,180
Transportation	1,027	16.0%	885	2,219	16.2%	1,909
Total	8,401	(0.2)%	8,417	24,869	(6.4)%	26,557

Second Quarter

Margin decreased $2.0 million due to the SCPSC-approved decrease in retail gas base rates under the RSA which became effective with the first billing cycle of November 2010.

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Year to Date

Margin decreased $6.3 million due to the SCPSC-approved decrease in retail gas base rates under the RSA which became effective with the first billing cycle of November 2010.  Total sales volumes decreased primarily due to decreased firm customer usage resulting from milder weather.

Other Operating Expenses

Other operating expenses were as follows: 

	Second Quarter					Year to Date
Millions of dollars	2011		%    Change	2010		2011		% Change	2010
Other operation and maintenance	$	127.5	(0.2)%	$	127.7	$	259.5	-	$	259.6
Depreciation and amortization	71.0		6.9%	66.4		141.9		6.9%	132.8
Other taxes	46.7		1.5%	46.0		94.1		5.0%	89.6

Second Quarter

Other operation and maintenance expenses decreased by $2.3 million due to lower compensation and other benefits.  This decrease was partially offset by $1.8 million due to higher generation, transmission and distribution expenses.  Depreciation and amortization expense increased in 2011 primarily due to net property additions.  Other taxes increased primarily due to higher property taxes.

Year to Date

Other operation and maintenance expenses decreased by $3.0 million due to lower customer service expenses and general expenses, including bad debt expense.  This decrease was partially offset by $2.2 million related to a SCPSC order allowing SCE&G to defer pension expense and income (see also the discussion at “Other Income (Expense)”).  Depreciation and amortization expense increased in 2011 primarily due to net property additions.  Other taxes increased primarily due to higher property taxes.

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	2011		2010			2011		2010
Income Statement Impact:
Employee benefit costs	$	-	$	(1.1	)	$	-	$	(2.2	)
Other income	-		(1.0		)	-		(2.0		)
Balance Sheet Impact:
Capital expenditures	0.8		1.4			1.6		2.9
Component of amount due from Summer Station co-owner	0.3		0.4			0.6		0.8
Regulatory asset	2.3		5.3			4.6		10.7
Total Pension Cost	$	3.4	$	5.0		$	6.8	$	10.2

No contribution to the pension trust will be necessary in or for 2011, nor will limitations on benefit payments apply.  Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts included in rates for its retail electric and gas distribution regulated operations.  In connection with the SCPSC’s July 2010 electric rate order and November 2010 natural gas RSA order, SCE&G began deferring all pension expense and income related to retail electric and gas 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.

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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 related to the construction of two nuclear electric generation units at the site of Summer Station was offset by the decrease in AFC related 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) for the three months ended June 30, 2011 were lower than the same period in 2010 primarily due to lower income before taxes, which excludes the allowance for equity funds used during construction, a nontaxable item, as well as by the recognition of certain previously deferred state income tax credits pursuant to SCE&G’s July 2010 retail electric rate order (see also the discussion at “Electric Operations”).

Year to Date

Income taxes (and the effective tax rate) for the six months ended June 30, 2011 were higher than the same period in 2010 primarily due to higher income before taxes, which excludes the allowance for equity funds used during construction, a nontaxable item, as well as 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

Consolidated SCE&G anticipates that its contractual cash obligations will be met through internally generated funds and the incurrence of additional short- and long-term indebtedness.  Consolidated SCE&G expects that, barring a future 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, 2011 was 2.82 and 3.18, respectively.

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
	June 30,			December 31,
Millions of dollars	2011			2010
Lines of credit:
Committed long-term
Total	$	1,100		$	1,100
LOC advances	-			-
Weighted average interest rate	-			-
Outstanding commercial paper (270 or fewer days)	$	475		$	381
Weighted average interest rate	.35		%	.42		%
Letters of credit supported by LOC	$	.3		$	.3
Available	$	625		$	719

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SCE&G and Fuel Company are parties to five-year credit agreements in the amount of $1.1 billion, of which $400 million relates to Fuel Company, which expire October 23, 2015.  These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, fossil fuel, and emission and other environmental allowances.  These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10% of the aggregate $1.1 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%.  Three other banks provide the remaining 6%. 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).

Consolidated SCE&G is obligated with respect to an aggregate of $68.3 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company.  These letters of credit expire, subject to renewal, in the fourth quarter of 2011.

At June 30, 2011, Consolidated SCE&G had net available liquidity of approximately $653 million.  Consolidated SCE&G regularly monitors the commercial paper and short-term credit markets to optimize the timing for repayment of any outstanding balance on its draws, while maintaining appropriate levels of liquidity.  Consolidated SCE&G’s long term debt portfolio has a weighted average maturity of approximately 19 years and bears an average cost of 6.20%.  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.

Consolidated SCE&G’s liquidity is favorably impacted due to the issuance of final rules by the IRS in late 2010 related to bonus depreciation.  In addition Consolidated SCE&G recognizes a cash benefit from the method being used to account for capital maintenance, which results in certain maintenance costs being treated as current expense for income tax purposes.  Consolidated SCE&G expects these strategies to generate approximately $60 million of cash flow for 2011.  In addition, in 2011 SCE&G has received capital contributions from SCANA of approximately $49 million and expects to receive an additional $47 million related to SCANA’s issuance of stock through various compensation and dividend reinvestment plans.

In May 2011, SCE&G issued $100 million of 5.45% first mortgage bonds maturing on February 1, 2041, which constituted a reopening of $250 million of its 5.45% first mortgage bonds issued in January 2011.  Proceeds from these sales were used to retire $150 million of SCE&G first mortgage bonds due February 1, 2011, to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

SCE&G paid approximately $31 million in 2011 to settle interest rate contracts associated with the issuance of long-term debt.

OTHER MATTERS

Nuclear Generation

SCE&G, on behalf of itself and as agent for Santee Cooper, has entered into a contractual agreement for the design and construction of two 1,117-MW nuclear generation units at the site of Summer Station.  The contract provides that SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the New 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 will be the operator of the New Units.  SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals $5.5 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.

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SCE&G’s latest Integrated Resource Plan filed with the SCPSC in February 2011 continues to support SCE&G’s need for 55 percent of the output of the two units.  As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units.  Santee Cooper has indicated that it will seek to reduce its 45 percent ownership in the New Units.  Santee Cooper has disclosed that, in March 2011, it entered into a non-binding letter of intent with OUC that may result in the execution of a power purchase agreement with an option for OUC to acquire a portion of Santee Cooper’s ownership interest in the New Units.  Similarly, Santee Cooper announced in July 2011 that it has entered into separate letters of intent with Duke and FMPA that may result in either or both of them acquiring a portion of Santee Cooper’s ownership interest in the New Units.  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.

In March 2011, a tsunami resulting from a massive earthquake severely damaged several nuclear generating units and their back-up cooling systems in Japan.  The impact of the disaster is being evaluated world-wide, and numerous political and regulatory bodies, including those in the United States, are seeking to determine if additional safety measures should be required at other existing nuclear facilities, as well as those planned for construction.  In particular, on July 12, 2011, the NRC’s Near-Term Task Force issued a report titled “Recommendations for Enhancing Reactor Safety in the 21st Century,” which SCE&G is evaluating.  SCE&G cannot predict what regulatory or other outcomes may be implemented in the United States, nor how such initiatives would impact SCE&G’s existing Summer Station or the licensing, construction or operation of the New Units.

In April 2011, the NRC and the USACE completed the FEIS for the New Units, concluding that there were no environmental impacts that would preclude issuing the COL for the New Units.  The NRC continues to compile its final safety evaluation report, which is expected to be completed in the summer of 2011.

Fuel Contract

On January 27, 2011, SCE&G, for itself and as agent for Santee Cooper, and Westinghouse entered into a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, Westinghouse will supply enriched nuclear fuel assemblies for Summer Station Unit 1 and the New Units.  Westinghouse will be SCE&G’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements of Summer Station Unit 1 and the New Units through 2033. SCE&G is dependent upon Westinghouse for providing fuel assemblies for the new AP1000 passive reactors in the New Units in the current and anticipated future absence of other commercially viable sources.  Westinghouse currently provides maintenance and engineering support to Summer Station Unit 1 under a services alliance arrangement, and SCE&G has also contracted for Westinghouse to provide similar support services to the New Units upon their completion and commencement of commercial operation in 2016 and 2019, respectively.

Air Quality

In 2005, the EPA issued the CAIR, which required 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.  SCE&G and GENCO 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.  On July 6, 2011 the EPA issued the Cross-State Air Pollution Rule.  This rule replaces CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  The rule requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  The air quality control installations that SCE&G and GENCO have completed should assist Consolidated SCE&G in complying with the Cross-State Air Pollution Rule.  Consolidated SCE&G will continue to pursue strategies to comply with all applicable environmental regulations.  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.

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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 and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units.  In March 2011, EPA proposed new standards for mercury and other specified air pollutants.  The proposed rule provides up to four years for facilities to meet the standards once promulgated.  The EPA is expected to finalize the rule in November 2011.  The proposed rule is currently being evaluated by Consolidated SCE&G. 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.

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 $8.7 million.  In addition, the National Park Service of the Department of the Interior made a demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina.  In May 2011, the parties agreed to settle for $3.75 million (which amount SCE&G had previously accrued) and are awaiting judicial approval of the settlement.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.  At June 30, 2011, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.6 million and are included in regulatory assets.

For additional information related to environmental matters and claims and litigation, see Note 9 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 for the year ended December 31, 2010.  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 4 and 6 of the condensed consolidated financial statements.

60

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 6 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 DT.  Fair value represents quoted market prices for these or similar instruments.

Expected Maturity:
Options
	Purchased Call
2011	(Long)
Strike Price (a)	4.78
Contract Amount (b)	6.4
Fair Value (b)	0.3
2012
Strike Price (a)	5.05
Contract Amount (b)	5.5
Fair Value (b)	0.4

(a)Weighted average, in dollars

(b)Millions of dollars

ITEM 4.  CONTROLS AND PROCEDURES

As of June 30, 2011, 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, 2011, 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, 2011 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 SEC 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, 2011			James E. Swan, IV
			Controller
			(Principal accounting officer)

63

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		Articles of Amendment effective April 25, 2011 (Filed as Exhibit 4.03 to Registration Statement No. 333-174796 and incorporated by reference herein)
3.04		X	Restated Articles of Incorporation of SCE&G, as adopted on December 30, 2009 (Filed as Exhibit 1 to Form 8-A (File Number 000-53860) and incorporated by reference herein)
3.05	X		By-Laws of SCANA as amended and restated as of February 19, 2009 (Filed as Exhibit 4.04 to Registration Statement No. 333-174796 and incorporated by reference herein)
3.06		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)
4.01	X		First Supplemental Indenture dated as of November 1, 2009 to Indenture dated as of November 1, 1989 between SCANA Corporation and The Bank of New York Mellon Trust Company, N. A. (successor to The Bank of New York), as Trustee) (Filed as Exhibit 99.01 to Registration Statement No. 333-174796 and incorporated by reference herein)
4.02	X		Junior Subordinated Indenture dated as of November 1, 2009 between SCANA Corporation and U. S. Bank National Association, as Trustee (Filed as Exhibit 99.02 to Registration Statement No. 333-174796 and incorporated by reference herein)
4.03	X		First Supplemental Indenture to Junior Subordinated Indenture referred to in Exhibit 4.02 dated as of November 1, 2009 (Filed as Exhibit 99.03 to Registration Statement No. 333-174796 and incorporated by reference herein)
*10.01	X	X	SCANA Executive Deferred Compensation Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.04 to Registration Statement No. 333-174796 and incorporated by reference herein)
*10.02	X	X	SCANA Supplemental Executive Retirement Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.05 to Registration Statement No. 333-174796 and incorporated by reference herein)
*10.03	X	X	SCANA Director Compensation and Deferral Plan (including amendments through April 21, 2011) (Filed as Exhibit 4.05 to Registration Statement No. 333-174796 and incorporated by reference herein)

64

	Applicable to Form 10-Q of
Exhibit No.	SCANA	SCE&G	Description
*10.04	X	X	SCANA Supplementary Executive Benefit Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.07 to Registration Statement No. 333-174796 and incorporated by reference herein)
*10.05	X	X	SCANA Short-Term Annual Incentive Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.08 to Registration Statement No. 333-174796 and incorporated by reference herein)
*10.06	X	X	SCANA Supplementary Key Executive Severance Benefits Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.09 to Registration Statement No. 333-174796 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	X	XBRL Instance Document
101. SCH**	X	X	XBRL Taxonomy Extension Schema
101. CAL**	X	X	XBRL Taxonomy Extension Calculation Linkbase
101. DEF**	X	X	XBRL Taxonomy Extension Definition Linkbase
101. LAB**	X	X	XBRL Taxonomy Extension Label Linkbase
101. PRE**	X	X	XBRL Taxonomy Extension Presentation Linkbase

*Management Contract or Compensatory Plan or Arrangement

**   Pursuant to Rule 406T of Regulation S-T, this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

65

EX-31.01

Exhibit 31.01

CERTIFICATION

I, William B. Timmerman, certify that:

1.I have reviewed this quarterly report on Form 10-Q of SCANA Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   August 4, 2011
	/s/William B. Timmerman
	William B. Timmerman
	Chairman of the Board and Chief Executive Officer

66

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Jimmy E. Addison, certify that:

1.I have reviewed this quarterly report on Form 10-Q of SCANA Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   August 4, 2011
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Senior Vice President and Chief Financial Officer

67

EX-31.03

Exhibit 31.03

CERTIFICATION

I, William B. Timmerman, certify that:

1.I have reviewed this quarterly report on Form 10-Q of South Carolina Electric & Gas Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   August 4, 2011
	/s William B. Timmerman
	William B. Timmerman
	Chairman of the Board and Chief Executive Officer

68

EX-31.04

Exhibit 31.04

CERTIFICATION

I, Jimmy E. Addison, certify that:

1.I have reviewed this quarterly report on Form 10-Q of South Carolina Electric & Gas Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   August 4, 2011
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Senior Vice President and Chief Financial Officer

69

EX-32.01

Exhibit 32.01

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of SCANA Corporation (the “Company”) on Form 10-Q for the quarter ended June 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: August 4, 2011

/s/William B. Timmerman

William B. Timmerman

Chairman of the Board and Chief Executive Officer

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

70

EX-32.02

Exhibit 32.02

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of SCANA Corporation (the “Company”) on Form 10-Q for the quarter ended June 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: August 4, 2011

/s/Jimmy E. Addison

Jimmy E. Addison

Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

71

EX-32.03

Exhibit 32.03

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of South Carolina Electric & Gas Company (the “Company”) on Form 10-Q for the quarter ended June 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: August 4, 2011

/s/William B. Timmerman

William B. Timmerman

Chairman of the Board and Chief Executive Officer

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

72

EX-32.04

Exhibit 32.04

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of South Carolina Electric & Gas Company (the “Company”) on Form 10-Q for the quarter ended June 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: August 4, 2011

/s/Jimmy E. Addison

Jimmy E. Addison

Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

73

XML



SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - SCEG

6 Months Ended

Jun. 30, 2011

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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 utilizing the treasury stock method.  The Company has issued no securities that would have an antidilutive effect on earnings per share.

A reconciliation of the weighted average number of common shares for year to date June 30 for basic and dilutive purposes is as follows:

	Quarterly		Year to Date
In Millions	2011	2010	2011	2010
Weighted Average Shares Outstanding  - Basic	128.5	125.2	128.2	124.5
Net effect of dilutive stock-based compensation plans and equity forward contracts	1.2	0.2	1.2	0.1
Weighted Average Shares - Diluted	129.7	125.4	129.4	124.6

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, 2011, such counterparties held 47% of PSNC Energy’s natural gas inventory, with a carrying value of $18.5 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, 2013.

New Accounting Matter

Effective for the first quarter of 2012, the Company will adopt accounting guidance that revises how comprehensive income is presented in its financial statements.  The Company does not expect the adoption of this guidance to impact results of operations, cash flows or financial position.

SOUTH CAROLINA ELECTRIC AND GAS COMPANY

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Variable Interest Entity

SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs), 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, SCE&G’s parent. 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 605 MW net generating capacity (summer rating). GENCO’s electricity is sold solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $496 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel and emission allowances. See also Note 4.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

New Accounting Matter

Effective for the first quarter of 2012, Consolidated SCE&G will adopt accounting guidance that revises how comprehensive income is presented in its financial statements.  Consolidated SCE&G does not expect the adoption of this guidance to impact results of operations, cash flows or financial position.

XML



CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $) In Millions, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Operating Revenues:
Electric	$ 616	$ 575	$ 1,174	$ 1,115
Gas - regulated	135	137	497	567
Gas - nonregulated	249	227	610	685
Total Operating Revenues	1,000	939	2,281	2,367
Operating Expenses:
Fuel used in electric generation	251	222	462	456
Purchased power	8	3	10	5
Gas purchased for resale	297	277	810	936
Other operation and maintenance	165	167	334	339
Depreciation and amortization	86	83	172	166
Other taxes	51	50	103	98
Total Operating Expenses	858	802	1,891	2,000
Operating Income	142	137	390	367
Other Income (Expense):
Other income	11	14	24	27
Other expenses	(9)	(9)	(19)	(19)
Interest charges, net of allowance for borrowed funds used during construction of $3, $3, $5 and $5	(70)	(66)	(139)	(131)
Allowance for equity funds used during construction	5	7	8	10
Total Other Expense	(63)	(54)	(126)	(113)
Income Before Income Tax Expense	79	83	264	254
Income Tax Expense	23	29	80	74
Income Available to Common Shareholders of SCANA	$ 56	$ 54	$ 184	$ 180
Per Common Share Data
Basic Earnings Per Share of Common Stock (in dollars per share)	$ 0.44	$ 0.43	$ 1.44	$ 1.45
Diluted Earnings Per Share of Common Stock (in dollars per share)	$ 0.43	$ 0.43	$ 1.42	$ 1.45
Weighted Average Common Shares Outstanding (millions)
Basic (in shares)	128.5	125.2	128.2	124.5
Diluted (in shares)	129.7	125.4	129.4	124.6
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 0.485	$ 0.475	$ 0.97	$ 0.95

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Interest charges, allowance for borrowed funds used during construction	$ 3	$ 3	$ 5	$ 5

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LONG-TERM DEBT AND LIQUIDITY - SCEG

6 Months Ended

Jun. 30, 2011

LONG-TERM DEBT AND LIQUIDITY

4. LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In May 2011, SCE&G issued $100 million of 5.45% first mortgage bonds maturing on February 1, 2041, which constituted a reopening of $250 million of its 5.45% first mortgage bonds issued in January 2011.  Proceeds from these sales were used to retire $150 million of SCE&G first mortgage bonds due February 1, 2011, to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

In February 2011, PSNC Energy issued $150 million of 4.59% unsecured senior notes due February 14, 2021. Proceeds from these notes were used to retire $150 million of medium term notes due February 15, 2011.

In May 2011, SCANA issued $300 million of its 4.75% medium term notes due May 15, 2021.  Proceeds from the sale of these notes were used by SCANA to pay at maturity $300 million of its 6.875% medium term notes.

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.

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						PSNC Energy
		June 30,		December 31,			June 30,			December 31,			June 30,		December 31,
Millions of dollars		2011		2010			2011			2010			2011		2010
Lines of credit:
Committed long-term
Total	$	300		$	300		$	1,100		$	1,100		$	100	$	100
LOC advances		-		-			-			-			-		-
Weighted average interest rate		-		-			-			-			-		-
Outstanding commercial paper (270 or fewer days)	$	71		$	39		$	475		$	381		-		-
Weighted average interest rate		.35	%	.35		%	.35		%	.42		%	-		-
Letters of credit supported by LOC	$	3		$	3		$	.3		$	.3		-		-
Available	$	226		$	258		$	625		$	719		$	100	$	100

SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million, $1.1 billion, of which $400 million relates to Fuel Company, and $100 million, respectively, which expire October 23, 2015.  These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, fossil fuel, and emission and other environmental allowances.  These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10% of the aggregate $1.5 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%.  Three other banks provide the remaining 6%. These bank credit facilities support the issuance of commercial paper by SCANA, SCE&G (including Fuel Company) and PSNC Energy. 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 SCANA, SCE&G (including Fuel Company) and PSNC Energy.

The Company is obligated with respect to an aggregate of $68.3 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company.  These letters of credit expire, subject to renewal, in the fourth quarter of 2011.

SOUTH CAROLINA ELECTRIC AND GAS COMPANY

LONG-TERM DEBT AND LIQUIDITY

4. LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In May 2011, SCE&G issued $100 million of 5.45% first mortgage bonds maturing on February 1, 2041, which constituted a reopening of $250 million of its 5.45% first mortgage bonds issued in January 2011.  Proceeds from these sales were used to retire $150 million of SCE&G first mortgage bonds due February 1, 2011, to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

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.

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
	June 30,			December 31,
Millions of dollars	2011			2010
Lines of credit:
Committed long-term
Total	$	1,100		$	1,100
LOC advances	-			-
Weighted average interest rate	-			-
Outstanding commercial paper (270 or fewer days)	$	475		$	381
Weighted average interest rate	.35		%	.42		%
Letters of credit supported by LOC	$	.3		$	.3
Available	$	625		$	719

SCE&G and Fuel Company are parties to five-year credit agreements in the amount of $1.1 billion, of which $400 million relates to Fuel Company, which expire October 23, 2015.  These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, fossil fuel, and emission and other environmental allowances.  These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10% of the aggregate $1.1 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%.  Three other banks provide the remaining 6%. 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).

Consolidated SCE&G is obligated with respect to an aggregate of $68.3 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company.  These letters of credit expire, subject to renewal, in the fourth quarter of 2011.

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DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

6 Months Ended

Jun. 30, 2011

DERIVATIVE FINANCIAL INSTRUMENTS

Natural gas derivative contracts outstanding

	Commodity and Other Energy Management Contracts (in DT)
Hedge designation	Gas Distribution	Retail Gas Marketing	Energy Marketing	Total
As of June 30, 2011
Cash flow	-	5,524,000	18,671,098	24,195,098
Not designated (a)	10,014,000	-	23,382,436	33,396,436
Total (a)	10,014,000	5,524,000	42,053,534	57,591,534
As of December 31, 2010
Cash flow	-	5,715,000	17,190,351	22,905,351
Not designated (b)	10,677,000	-	20,588,581	31,265,581
Total (b)	10,677,000	5,715,000	37,778,932	54,170,932

(a)  Includes an aggregate  8,019,000 DT related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 6,485,536 DT related to basis swap contracts in Energy Marketing.

Fair value of energy-related derivatives and interest rate derivatives balance sheet location

	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, 2011
Derivatives designated as hedging instruments
Interest rate contracts		Prepayments and other		$		2	Other current liabilities		$		14
		Other deferred debits		4			Other deferred credits		30
Commodity contracts		Other current liabilities		1			Other current liabilities		3
							Other deferred credits		2
Total				$		7			$		49
Derivatives not designated as hedging instruments
Commodity contracts		Prepayments and other		$		3
Energy management contracts		Prepayments and other				4	Other deferred debits		$		1
		Other deferred debits		3			Other current liabilities		4
		Other deferred credits		1			Other deferred credits		3
Total				$		11			$		8
As of December 31, 2010
Derivatives designated as hedging instruments
Interest rate contracts		Other current assets	$		1			Other current liabilities	$	57
		Other deferred debits			7			Other deferred credits		25
Commodity contracts		Other current liabilities	1					Other current liabilities	5
								Other deferred credits	2
Total			$		9				$	89
Derivatives not designated as hedging instruments
Commodity contracts		Prepayments and other	$			3
Energy management contracts		Prepayments and other	7					Prepayments and other	$			1
		Other deferred debits	2					Other current liabilities	6
								Other deferred credits	2
Total			$			12			$			9

(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.

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, 2011
Interest rate contracts	$	(15	)	Interest expense	$	-
Six Months Ended June 30,  2011
Interest rate contracts	$	(9	)	Interest expense	$	(1	)
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)
		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, 2011
Interest rate contracts	$	(14	)	Interest expense	$	(1	)
Commodity contracts		(1	)	Gas Purchased for resale		-
Total	$	(15	)		$	(1	)
Six Months Ended June 30, 2011
Interest rate contracts	$	(11	)	Interest expense	$	(2	)
Commodity contracts		(2	)	Gas Purchased for resale		(4	)
Total	$	(13	)		$	(6	)
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)

Derivatives not designated as Hedging Instruments Gain (Loss) Recognized in Income

	Gain (Loss) Recognized in Income
Derivatives not designated as
Hedging Instruments
Millions of dollars	Location	2011			2010
Second Quarter
Commodity contracts	Gas purchased for resale	$	-		$	(1	)
Year to Date
Commodity contracts	Gas purchased for resale	$	(1	)	$	(2	)

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CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Assets
Utility Plant In Service	$ 11,901	$ 11,714
Accumulated Depreciation and Amortization	(3,599)	(3,495)
Construction Work in Progress	1,284	1,081
Nuclear Fuel, Net of Accumulated Amortization	133	132
Goodwill, net of accumulated amortization and writedown of $276	230	230
Utility Plant, Net	9,949	9,662
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $127 and $118	302	299
Assets held in trust, net-nuclear decommissioning	80	76
Other investments	87	78
Nonutility Property and Investments, Net	469	453
Current Assets:
Cash and cash equivalents	166	55
Receivables, net of allowance for uncollectible accounts of $6 and $9	627	837
Inventories (at average cost):
Fuel and gas supply	284	316
Materials and supplies	128	125
Emission allowances	4	6
Prepayments and other	207	271
Deferred income taxes	19	21
Total Current Assets	1,435	1,631
Deferred Debits and Other Assets:
Regulatory assets	1,128	1,061
Other	163	161
Total Deferred Debits and Other Assets	1,291	1,222
Total	13,144	12,968
Capitalization and Liabilities
Common Equity	3,805	3,702
Long-Term Debt, net	4,379	4,152
Total Capitalization	8,184	7,854
Current Liabilities:
Short-term borrowings	546	420
Current portion of long-term debt	286	337
Accounts payable	379	526
Customer deposits and customer prepayments	96	100
Taxes accrued	83	146
Interest accrued	74	72
Dividends declared	63	61
Derivative financial instruments	20	65
Other	106	140
Total Current Liabilities	1,653	1,867
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,429	1,391
Deferred investment tax credits	43	56
Asset retirement obligations	510	497
Other postretirement benefits	205	202
Regulatory liabilities	931	913
Other	189	188
Total Deferred Credits and Other Liabilities	3,307	3,247
Commitments and Contingencies (Note 9)
Total	$ 13,144	$ 12,968

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - SCEG (USD $) In Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010		Jun. 30, 2011		Jun. 30, 2010
Other Comprehensive Income, net of tax:
Reclassification to net income - amortization of deferred employee benefit plan costs, net of taxes							$ 1
Comprehensive income attributable to SCANA Corporation	42	[1]	29	[1]	177	[1]	150	[1]
SOUTH CAROLINA ELECTRIC AND GAS COMPANY
Net Income	61		63		132		127
Other Comprehensive Income, net of tax:
Reclassification to net income - amortization of deferred employee benefit plan costs, net of taxes							1
Total Comprehensive Income	61		63		132		128
Less comprehensive income attributable to noncontrolling interest	(2)		(3)		(5)		(5)
Comprehensive income attributable to SCANA Corporation	$ 59	[2]	$ 60	[2]	$ 127	[2]	$ 123	[2]

[1] Accumulated other comprehensive loss totaled $53.2 million as of June 30, 2011 and $46.6 million as of December 31, 2010.

[2] Accumulated other comprehensive loss totaled $2.6 million as of June 30, 2011 and $2.7 million as of December 31, 2010.

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SEGMENT OF BUSINESS INFORMATION (Tables)

6 Months Ended

Jun. 30, 2011

SEGMENT OF BUSINESS INFORMATION

Schedule of revenue, income and assets by segments

	External			Intersegment			Operating			Income Available to			Segment
Millions of dollars		Revenue			Revenue			Income			Common Shareholders			Assets
Three Months Ended June 30, 2011
Electric Operations		$	616		$	2		$	140			n/a
Gas Distribution			132			-			2			n/a
Retail Gas Marketing			78			-			n/a		$	(3	)
Energy Marketing			172			52			n/a			1
All Other			10			104			3			-
Adjustments/Eliminations			(8	)		(158	)		(3	)		58
Consolidated Total		$	1,000		$	-		$	142		$	56
Six Months Ended June 30, 2011
Electric Operations		$	1,174		$	4		$	262			n/a		$	8,108
Gas Distribution			492			-			86			n/a			2,178
Retail Gas Marketing			280			-			n/a		$	19			178
Energy Marketing			330			97			n/a			2			123
All Other			20			206			8			1			1,287
Adjustments/Eliminations			(15	)		(307	)		34			162			1,270
Consolidated Total		$	2,281		$	-		$	390		$	184		$	13,144

	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
Retail Gas Marketing		74			-			n/a		$	(5	)
Energy Marketing		153			42			n/a			2
All Other		10			105			5			(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
Retail Gas Marketing		336			-			n/a		$	24			157
Energy Marketing		349			89			n/a			2			116
All Other		18			202			10			(6	)		1,206
Adjustments/Eliminations		(13	)		(295	)		40			160			1,168
Consolidated Total	$	2,367		$	-		$	367		$	180		$	12,252

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - SCEG (USD $) In Millions	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Cash paid for interest, capitalized interest	$ 5	$ 5
SOUTH CAROLINA ELECTRIC AND GAS COMPANY
Cash paid for interest, capitalized interest	$ 4	$ 5

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LONG-TERM DEBT AND LIQUIDITY

6 Months Ended

Jun. 30, 2011

LONG-TERM DEBT AND LIQUIDITY

LONG-TERM DEBT AND LIQUIDITY

4. LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In May 2011, SCE&G issued $100 million of 5.45% first mortgage bonds maturing on February 1, 2041, which constituted a reopening of $250 million of its 5.45% first mortgage bonds issued in January 2011.  Proceeds from these sales were used to retire $150 million of SCE&G first mortgage bonds due February 1, 2011, to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

In February 2011, PSNC Energy issued $150 million of 4.59% unsecured senior notes due February 14, 2021. Proceeds from these notes were used to retire $150 million of medium term notes due February 15, 2011.

In May 2011, SCANA issued $300 million of its 4.75% medium term notes due May 15, 2021.  Proceeds from the sale of these notes were used by SCANA to pay at maturity $300 million of its 6.875% medium term notes.

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.

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						PSNC Energy
		June 30,		December 31,			June 30,			December 31,			June 30,		December 31,
Millions of dollars		2011		2010			2011			2010			2011		2010
Lines of credit:
Committed long-term
Total	$	300		$	300		$	1,100		$	1,100		$	100	$	100
LOC advances		-		-			-			-			-		-
Weighted average interest rate		-		-			-			-			-		-
Outstanding commercial paper (270 or fewer days)	$	71		$	39		$	475		$	381		-		-
Weighted average interest rate		.35	%	.35		%	.35		%	.42		%	-		-
Letters of credit supported by LOC	$	3		$	3		$	.3		$	.3		-		-
Available	$	226		$	258		$	625		$	719		$	100	$	100

SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million, $1.1 billion, of which $400 million relates to Fuel Company, and $100 million, respectively, which expire October 23, 2015.  These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, fossil fuel, and emission and other environmental allowances.  These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10% of the aggregate $1.5 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%.  Three other banks provide the remaining 6%. These bank credit facilities support the issuance of commercial paper by SCANA, SCE&G (including Fuel Company) and PSNC Energy. 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 SCANA, SCE&G (including Fuel Company) and PSNC Energy.

The Company is obligated with respect to an aggregate of $68.3 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company.  These letters of credit expire, subject to renewal, in the fourth quarter of 2011.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Earnings Per Share
Weighted Average Shares Outstanding - Basic (in shares)	128.5	125.2	128.2	124.5
Net effect of dilutive stock-based compensation plans and equity forward contracts (in shares)	1.2	0.2	1.2	0.1
Weighted Average Shares - Diluted (in shares)	129.7	125.4	129.4	124.6
PSNC Energy
Asset Management and Supply Service Agreements
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)	47.00%		47.00%
Natural gas inventory, carrying amount	$ 18.5		$ 18.5

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CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - SCEG (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Utility Plant	$ 9,949	$ 9,662
Receivables, allowance for uncollectible accounts	6	9
Current Assets	1,435	1,631
Deferred Debits and Other Assets	1,291	1,222
SOUTH CAROLINA ELECTRIC AND GAS COMPANY
Utility Plant	8,458	8,198
Receivables, allowance for uncollectible accounts	3	3
Current Assets	922	1,060
Deferred Debits and Other Assets	1,260	1,190
SOUTH CAROLINA ELECTRIC AND GAS COMPANY | VIEs
Utility Plant	630	634
Current Assets	203	221
Deferred Debits and Other Assets	$ 42	$ 43

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Carrying Amount
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	$ 4,664.9	$ 4,488.3
Estimated Fair Value
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	$ 5,016.2	$ 4,840.5

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EMPLOYEE BENEFIT PLANS (Tables)

6 Months Ended

Jun. 30, 2011

EMPLOYEE BENEFIT PLANS

Components of net periodic benefit cost

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2011			2010			2011		2010
Three months ended June 30,
Service cost	$	4.6		$	4.8		$	1.1	$	1.1
Interest cost	11.1			11.9			3.0		3.2
Expected return on assets	(16.2		)	(16.5		)	-		-
Prior service cost amortization	1.8			1.8			0.3		0.2
Transition obligation amortization	-			-			0.2		0.1
Amortization of actuarial loss	3.0			4.3			0.1		0.1
Net periodic benefit cost	$	4.3		$	6.3		$	4.7	$	4.7
Six months ended June 30,
Service cost	$	9.2		$	9.5		$	2.2	$	2.2
Interest cost	22.2			23.7			6.0		6.2
Expected return on assets	(32.4		)	(32.9		)	-		-
Prior service cost amortization	3.6			3.7			0.6		0.5
Transition obligation amortization	-			-			0.4		0.3
Amortization of actuarial loss	6.0			8.6			0.2		0.2
Net periodic benefit cost	$	8.6		$	12.6		$	9.4	$	9.4

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COMMITMENTS AND CONTINGENCIES

6 Months Ended

Jun. 30, 2011

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

9. COMMITMENTS AND CONTINGENCIES

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.

Environmental

SCE&G

In 2005, the EPA issued the CAIR, which required 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.  SCE&G and GENCO 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.  On July 6, 2011 the EPA issued the Cross-State Air Pollution Rule.  This rule replaces CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  The rule requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  The air quality control installations that SCE&G and GENCO have completed should assist the Company in complying with the Cross-State Air Pollution Rule.  The Company will continue to pursue strategies to comply with all applicable environmental regulations.  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 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 and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units.  In March 2011, the EPA proposed new standards for mercury and other specified air pollutants.  The proposed rule provides up to four years for facilities to meet the standards once promulgated.  The EPA is expected to finalize the rule in November 2011.  The proposed rule 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.

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 $8.7 million.  In addition, the National Park Service of the Department of the Interior made a demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina.  In May 2011, the parties agreed to settle for $3.75 million (which amount SCE&G had previously accrued) and are awaiting judicial approval of the settlement.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.  At June 30, 2011, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.6 million and are included in regulatory assets.

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 $3.2 million, which reflects its estimated remaining liability at June 30, 2011. PSNC Energy expects to recover through rates any costs allocable to PSNC Energy arising from the remediation of these sites.

Nuclear Generation

SCE&G, on behalf of itself and as agent for Santee Cooper has entered into a contractual agreement for the design and construction of two 1,117-MW nuclear generation units at the site of Summer Station.  The contract provides that SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the New 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 will be the operator of the New Units.  SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals $5.5 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 in February 2011 continues to support SCE&G’s need for 55 percent of the output of the two units.  As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units.  Santee Cooper has indicated that it will seek to reduce its 45 percent ownership in the New Units.  Santee Cooper has disclosed that, in March 2011, it entered into a non-binding letter of intent with OUC that may result in the execution of a power purchase agreement with an option for OUC to acquire a portion of Santee Cooper’s ownership interest in the New Units.  Similarly, Santee Cooper announced in July 2011 that it has entered into separate letters of intent with Duke and FMPA that may result in either or both of them acquiring a portion of Santee Cooper’s ownership interest in the New Units.   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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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Accumulated other comprehensive loss	$ 53.2	$ 46.6

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DERIVATIVE FINANCIAL INSTRUMENTS (Details 2) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Derivatives designated as hedging instruments
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives Fair Value	$ 7	$ 9
Liability Derivatives Fair Value	49	89
Derivatives designated as hedging instruments | Interest rate contracts | Prepayments and other
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives Fair Value	2
Derivatives designated as hedging instruments | Interest rate contracts | Other deferred debits
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives Fair Value	4	7
Derivatives designated as hedging instruments | Interest rate contracts | Other current assets
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives Fair Value		1
Derivatives designated as hedging instruments | Interest rate contracts | Other current liabilities
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives Fair Value	14	57
Derivatives designated as hedging instruments | Interest rate contracts | Other deferred credits
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives Fair Value	30	25
Derivatives designated as hedging instruments | Commodity contracts | Other current liabilities
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives Fair Value	1	1
Liability Derivatives Fair Value	3	5
Derivatives designated as hedging instruments | Commodity contracts | Other deferred credits
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives Fair Value	2	2
Derivatives not designated as hedging instruments
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives Fair Value	11	12
Liability Derivatives Fair Value	8	9
Derivatives not designated as hedging instruments | Commodity contracts | Prepayments and other
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives Fair Value	3	3
Derivatives not designated as hedging instruments | Other energy management contracts. | Prepayments and other
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives Fair Value	4	7
Liability Derivatives Fair Value		1
Derivatives not designated as hedging instruments | Other energy management contracts. | Other deferred debits
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives Fair Value	3	2
Liability Derivatives Fair Value	1
Derivatives not designated as hedging instruments | Other energy management contracts. | Other current liabilities
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives Fair Value	4	6
Derivatives not designated as hedging instruments | Other energy management contracts. | Other deferred credits
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives Fair Value	1
Liability Derivatives Fair Value	$ 3	$ 2

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DERIVATIVE FINANCIAL INSTRUMENTS

6 Months Ended

Jun. 30, 2011

DERIVATIVE FINANCIAL INSTRUMENTS

DERIVATIVE FINANCIAL INSTRUMENTS

6. 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.

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.  Cash settlement of commodity derivatives are classified as an operating activity in the condensed consolidated statements of cash flows.

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 recorded 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.  Gains on certain swaps which were terminated prior to maturity of the underlying debt instruments 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 portion of settlement payments made or received upon termination are amortized to interest expense over the term of the underlying debt.  These settlements are classified as an investing activity in the condensed consolidated statements of cash flows.

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, 2011
Cash flow	-	5,524,000	18,671,098	24,195,098
Not designated (a)	10,014,000	-	23,382,436	33,396,436
Total (a)	10,014,000	5,524,000	42,053,534	57,591,534
As of December 31, 2010
Cash flow	-	5,715,000	17,190,351	22,905,351
Not designated (b)	10,677,000	-	20,588,581	31,265,581
Total (b)	10,677,000	5,715,000	37,778,932	54,170,932

(a)  Includes an aggregate  8,019,000 DT related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 6,485,536 DT related to basis swap contracts in Energy Marketing.

At June 30, 2011 and December 31, 2010, the Company was party to interest rate swaps designated as fair value hedges with an aggregate notional amount of $253.2 million and $556.4 million, respectively, and was party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $572.6 million and $1.1 billion, 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, 2011
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other		$		2	Other current liabilities		$		14
	Other deferred debits		4			Other deferred credits		30
Commodity contracts	Other current liabilities		1			Other current liabilities		3
						Other deferred credits		2
Total			$		7			$		49
Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other		$		3
Energy management contracts	Prepayments and other				4	Other deferred debits		$		1
	Other deferred debits		3			Other current liabilities		4
	Other deferred credits		1			Other deferred credits		3
Total			$		11			$		8
As of December 31, 2010
Derivatives designated as hedging instruments
Interest rate contracts	Other current assets	$		1			Other current liabilities	$	57
	Other deferred debits			7			Other deferred credits		25
Commodity contracts	Other current liabilities	1					Other current liabilities	5
							Other deferred credits	2
Total		$		9				$	89
Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other	$			3
Energy management contracts	Prepayments and other	7					Prepayments and other	$			1
	Other deferred debits	2					Other current liabilities	6
							Other deferred credits	2
Total		$			12			$			9

(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 deferred gains on previously terminated swaps as discussed above, resulted in reductions to interest expense of $1.5 million and $4.0 million for the three and six months ended June 30, 2011, respectively,  and $2.0 million and $5.2 million for the three and six months ended June 30, 2010, 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, 2011
Interest rate contracts	$	(15	)	Interest expense	$	-
Six Months Ended June 30,  2011
Interest rate contracts	$	(9	)	Interest expense	$	(1	)
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)
		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, 2011
Interest rate contracts	$	(14	)	Interest expense	$	(1	)
Commodity contracts		(1	)	Gas Purchased for resale		-
Total	$	(15	)		$	(1	)
Six Months Ended June 30, 2011
Interest rate contracts	$	(11	)	Interest expense	$	(2	)
Commodity contracts		(2	)	Gas Purchased for resale		(4	)
Total	$	(13	)		$	(6	)
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)

As of June 30, 2011, 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 $1.4 million as an increase to gas cost and approximately $4.5 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of June 30, 2011, 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	2011			2010
Second Quarter
Commodity contracts	Gas purchased for resale	$	-		$	(1	)
Year to Date
Commodity contracts	Gas purchased for resale	$	(1	)	$	(2	)

Hedge Ineffectiveness

Other gains (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three and six months ended June 30, 2011 and 2010.

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, 2011 and December 31, 2010, the Company has posted $17.0 million and $20.0 million, respectively, 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, 2011 and December 31, 2010, the Company would be required to post an additional $36.9 million and $74.0 million, respectively, 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, 2011 and December 31, 2010 are $53.9 million and $94.0 million, respectively.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

6 Months Ended

Jun. 30, 2011

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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 utilizing the treasury stock method.  The Company has issued no securities that would have an antidilutive effect on earnings per share.

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, 2011, such counterparties held 47% of PSNC Energy’s natural gas inventory, with a carrying value of $18.5 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, 2013.

Income Taxes

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  The Company has accrued $0.8 million of interest expense through June 2011.

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

6 Months Ended

Jun. 30, 2011

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

7. 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, 2011
Assets -	Available for sale securities	$	3	$	-
	Interest rate contracts		-		6
	Commodity contracts		2		2
	Energy management contracts		-		8
Liabilities -	Interest rate contracts		-		44
	Commodity contracts		1		4
	Energy management contracts		-		8
As of December 31, 2010
Assets -	Available for sale securities	$	3	$	-
	Interest rate contracts		-		8
	Commodity contracts		2		2
	Energy management contracts		-		9
Liabilities -	Interest rate contracts		-		82
	Commodity contracts		1		6
	Energy management contracts		-		11

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, 2011 and December 31, 2010 were as follows:

	June 30, 2011				December 31, 2010
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,664.9	$	5,016.2	$	4,488.3	$	4,840.5

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.

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LONG-TERM DEBT AND LIQUIDITY (Details) (USD $) In Millions, unless otherwise specified		1 Months Ended							3 Months Ended		3 Months Ended
	Jun. 30, 2011	Feb. 28, 2011 PSNC Energy 4.59 % unsecured senior notes due February 14, 2021	May 31, 2011 SCE&G 5.45 % first mortgage bonds	Jan. 31, 2011 SCE&G 5.45 % first mortgage bonds	May 31, 2011 4.75% medium term notes due May 15, 2021 SCANA	May 31, 2011 6.875% medium term notes SCANA	Feb. 28, 2011 Medium term notes due February 15, 2011	Jan. 31, 2011 SCE&G First Mortgage Bonds due February 1, 2011	Jun. 30, 2011 Line of credit	Jun. 30, 2011 Line of credit Fuel Company	Jun. 30, 2011 Commercial paper	Jun. 30, 2011 Commercial paper SCANA	Dec. 31, 2010 Commercial paper SCANA	Jun. 30, 2011 Commercial paper SCE&G (including Fuel Company)	Dec. 31, 2010 Commercial paper SCE&G (including Fuel Company)	Jun. 30, 2011 SCANA	Dec. 31, 2010 SCANA	Jun. 30, 2011 SCE&G (including Fuel Company)	Dec. 31, 2010 SCE&G (including Fuel Company)	Jun. 30, 2011 PSNC Energy	Dec. 31, 2010 PSNC Energy	Jun. 30, 2011 Wells Fargo Bank, National Association	Jun. 30, 2011 Bank of America, N.A.	Jun. 30, 2011 Morgan Stanly Bank, N.A.	Jun. 30, 2011 Branch Banking and Trust Company	Jun. 30, 2011 Credit Suisse AG, Cayman Islands Branch	Jun. 30, 2011 JPMorgan Chase Bank, N.A.	Jun. 30, 2011 Mizuho Corporate Bank, Ltd	Jun. 30, 2011 TD Bank, N.A.	Jun. 30, 2011 UBS Loan Finance LLC	Jun. 30, 2011 Deutsche Bank AG, New York Branch	Jun. 30, 2011 Union Bank, N.A.	Jun. 30, 2011 US Bank National Association	Jun. 30, 2011 Three other banks
Long-term Debt
Face amount of debt issued		$ 150	$ 100	$ 250	$ 300
Retirement of debt						300	150	150
Stated interest rate (as a percent)		4.59%	5.45%	5.45%	4.75%	6.875%
Lines of credit:
Committed long-term line of credit, Total	1,500									400						300	300	1,100	1,100	100	100
LOC advances																0		0		0
LOC advances, weighted average interest rate (as a percent)																0.00%		0.00%		0.00%
Outstanding commercial paper (270 or fewer days)												71	39	475	381
Commercial paper, weighted average interest rate (as a percent)												0.35%	0.35%	0.35%	0.42%
Commercial paper, maximum term											270D
Letters of credit supported by LOC																3.0	3.0	0.3	0.3
Available amount under lines of credit																226	258	625	719	100	100
Line of credit facilities, term of credit agreements									5Y
Percentage of aggregate credit facilities provided by banks (as a percent)																						10.00%	10.00%	10.00%	8.00%	8.00%	8.00%	8.00%	8.00%	8.00%	5.30%	5.30%	5.30%	6.00%
Number of other banks																																		3
Face value of Industrial Revenue Bonds issued, proceeds of which were availed as loan	$ 68.3

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INCOME TAXES

6 Months Ended

Jun. 30, 2011

INCOME TAXES

INCOME TAXES

5. INCOME TAXES

In connection with the change in method of accounting for certain repair costs in 2010, the Company identified approximately $36 million of unrecognized tax benefit.  Because this method change is primarily a temporary difference, this additional benefit, if recognized, would not have a significant effect on the effective tax rate.  Within the next 12 months, it is reasonably possible that this unrecognized tax benefit could increase by as much as $12 million or decrease by as much as $36 million.  The events that could cause these changes are direct settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities, or the lapse of an applicable statute of limitation.  No other material changes in the status of the Company’s tax positions have occurred through June 30, 2011.

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  The Company has accrued $0.8 million of interest expense through June 2011.

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COMMON EQUITY - SCEG

6 Months Ended

Jun. 30, 2011

COMMON EQUITY

3. COMMON EQUITY

SCANA issued common stock valued at $50.1 million (at time of issue) during the six months ended June 30, 2011 through various compensation and dividend reinvestment plans (including the Stock Purchase Savings Plan), including the exercise of approximately 19,600 stock options during the period.  In addition, in May 2010 SCANA entered into forward sale contracts for approximately 6.6 million common shares to be settled no later than February 29, 2012.  There have been no shares issued under the forward sales contracts.

Authorized shares of common stock were 200 million as of June 30, 2011 and 150 million as of December 31, 2010.

SOUTH CAROLINA ELECTRIC AND GAS COMPANY

COMMON EQUITY

3. COMMON EQUITY

Changes in common equity during the six months ended June 30, 2011 and 2010 were as follows:

Millions of dollars	Common Equity			Noncontrolling Interest			Total Equity
Balance at January 1, 2011	$	3,436		$	105		$	3,541
Capital contribution from parent	49			-			49
Dividends declared	(96		)	(4		)	(100		)
Comprehensive income	127			5			132
Balance as of June 30, 2011	$	3,516		$	106		$	3,622

Balance at January 1, 2010	$	3,162		$	97		$	3,259
Capital contribution from parent	105			-			105
Dividends declared	(91		)	(3		)	(94		)
Comprehensive income	122			5			127
Balance as of June 30, 2010	$	3,298		$	99		$	3,397

Authorized shares of common stock were 50 million as of June 30, 2011 and December 31, 2010.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) (USD $) In Millions	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash paid for interest, capitalized interest	$ 5	$ 5

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

6 Months Ended

Jun. 30, 2011

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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 utilizing the treasury stock method.  The Company has issued no securities that would have an antidilutive effect on earnings per share.

A reconciliation of the weighted average number of common shares for year to date June 30 for basic and dilutive purposes is as follows:

	Quarterly		Year to Date
In Millions	2011	2010	2011	2010
Weighted Average Shares Outstanding  - Basic	128.5	125.2	128.2	124.5
Net effect of dilutive stock-based compensation plans and equity forward contracts	1.2	0.2	1.2	0.1
Weighted Average Shares - Diluted	129.7	125.4	129.4	124.6

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, 2011, such counterparties held 47% of PSNC Energy’s natural gas inventory, with a carrying value of $18.5 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, 2013.

New Accounting Matter

Effective for the first quarter of 2012, the Company will adopt accounting guidance that revises how comprehensive income is presented in its financial statements.  The Company does not expect the adoption of this guidance to impact results of operations, cash flows or financial position.

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COMMITMENTS AND CONTINGENCIES (Details) (USD $)	6 Months Ended	12 Months Ended		6 Months Ended	1 Months Ended		6 Months Ended
	Jun. 30, 2011	Dec. 31, 2005	Dec. 31, 2010	Jun. 30, 2011 SCE&G Nuclear electric generation units MW	May 31, 2011 SCE&G	Mar. 31, 2011 SCE&G	Jun. 30, 2011 SCE&G	Jun. 30, 2011 PSNC Energy
Nuclear Insurance
Federal limit on public liability claims from nuclear incident, approximate	$ 12,600,000,000
Maximum liability assessment per reactor for each nuclear incident	117,500,000						78,300,000
Maximum yearly assessment per reactor	17,500,000						11,700,000
Proportionate ownership share in Summer Station Unit 1							two-thirds
Proportionate ownership share of the other owner in Summer Station Unit 1							one-third
Maximum retrospective insurance premium per nuclear incident							14,200,000
Environmental
Number of states required to reduce emissions to attain mandated levels		28
Number of phases set by CAIR to attain emission limit		2
Maximum number of years required to meet the new standards for mercury and other specified air pollutants						4
Number of sites decommissioned that contain residues of by-product chemicals							4
Additional costs incurred for remediation							8,700,000
Initial demand for costs and damages relating to a MGP site in South Carolina							9,100,000
Settlement amount					3,750,000
Deferred costs, net of costs previously recovered through rates and insurance settlements included in regulatory assets							25,600,000
Number of sites that require environmental clean-up								5
Regulatory assets	1,128,000,000		1,061,000,000					3,200,000
Nuclear Generation
Number of nuclear electric generation units				2
Generation capacity (in MW)				1,117
Percentage applicable to the Company (as a percent)				55.00%
Percentage applicable to joint owner 2 (as a percent)				45.00%
Estimated cash outflow for plant costs and related transmission infrastructure costs of nuclear electric generation site				$ 5,500,000,000
Basis for determination of the projected plant costs and related transmission infrastructure costs				one-year and five-year escalation rates

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COMMON EQUITY (Details) (USD $) In Millions, except Share data			1 Months Ended	6 Months Ended
	Jun. 30, 2011	Dec. 31, 2010	May 31, 2010 Common Stock	Jun. 30, 2011 Common Stock
Common equity
Common stock issued under various compensation and dividend reinvestment plans, including the exercise of stock options				$ 50.1
Exercise of stock options				19,600
Number of shares underlying forward sales contracts (in shares)			6,600,000
Common Stock, Shares Authorized	200,000,000	150,000,000

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COMMITMENTS AND CONTINGENCIES - SCEG

6 Months Ended

Jun. 30, 2011

COMMITMENTS AND CONTINGENCIES

9. COMMITMENTS AND CONTINGENCIES

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.

Environmental

SCE&G

In 2005, the EPA issued the CAIR, which required 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.  SCE&G and GENCO 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.  On July 6, 2011 the EPA issued the Cross-State Air Pollution Rule.  This rule replaces CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  The rule requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  The air quality control installations that SCE&G and GENCO have completed should assist the Company in complying with the Cross-State Air Pollution Rule.  The Company will continue to pursue strategies to comply with all applicable environmental regulations.  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 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 and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units.  In March 2011, the EPA proposed new standards for mercury and other specified air pollutants.  The proposed rule provides up to four years for facilities to meet the standards once promulgated.  The EPA is expected to finalize the rule in November 2011.  The proposed rule 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.

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 $8.7 million.  In addition, the National Park Service of the Department of the Interior made a demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina.  In May 2011, the parties agreed to settle for $3.75 million (which amount SCE&G had previously accrued) and are awaiting judicial approval of the settlement.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.  At June 30, 2011, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.6 million and are included in regulatory assets.

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 $3.2 million, which reflects its estimated remaining liability at June 30, 2011. PSNC Energy expects to recover through rates any costs allocable to PSNC Energy arising from the remediation of these sites.

Nuclear Generation

SCE&G, on behalf of itself and as agent for Santee Cooper has entered into a contractual agreement for the design and construction of two 1,117-MW nuclear generation units at the site of Summer Station.  The contract provides that SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the New 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 will be the operator of the New Units.  SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals $5.5 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 in February 2011 continues to support SCE&G’s need for 55 percent of the output of the two units.  As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units.  Santee Cooper has indicated that it will seek to reduce its 45 percent ownership in the New Units.  Santee Cooper has disclosed that, in March 2011, it entered into a non-binding letter of intent with OUC that may result in the execution of a power purchase agreement with an option for OUC to acquire a portion of Santee Cooper’s ownership interest in the New Units.  Similarly, Santee Cooper announced in July 2011 that it has entered into separate letters of intent with Duke and FMPA that may result in either or both of them acquiring a portion of Santee Cooper’s ownership interest in the New Units.   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.

SOUTH CAROLINA ELECTRIC AND GAS COMPANY

COMMITMENTS AND CONTINGENCIES

9. COMMITMENTS AND CONTINGENCIES

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.

Environmental

In 2005, the EPA issued the CAIR, which required 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.  SCE&G and GENCO 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.  On July 6, 2011 the EPA issued the Cross-State Air Pollution Rule.  This rule replaces CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  The rule requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  The air quality control installations that SCE&G and GENCO have completed should assist Consolidated SCE&G in complying with the Cross-State Air Pollution Rule.  Consolidated SCE&G will continue to pursue strategies to comply with all applicable environmental regulations.  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 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 and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units.  In March 2011, the EPA proposed new standards for mercury and other specified air pollutants.  The proposed rule provides up to four years for facilities to meet the standards once promulgated.  The EPA is expected to finalize the rule in November 2011.  The proposed rule 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.

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 $8.7 million.  In addition, the National Park Service of the Department of the Interior made a demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina.  In May 2011, the parties agreed to settle for $3.75 million (which amount SCE&G had previously accrued) and are awaiting judicial approval of the settlement.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.  At June 30, 2011, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.6 million and are included in regulatory assets.

Nuclear Generation

SCE&G, on behalf of itself and as agent for Santee Cooper has entered into a contractual agreement for the design and construction of two 1,117-MW nuclear generation units at the site of Summer Station.  The contract provides that SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the New 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 will be the operator of the New Units.  SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals $5.5 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 in February 2011 continues to support SCE&G’s need for 55 percent of the output of the two units.  As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units.  Santee Cooper has indicated that it will seek to reduce its 45 percent ownership in the New Units.  Santee Cooper has disclosed that, in March 2011, it entered into a non-binding letter of intent with OUC that may result in the execution of a power purchase agreement with an option for OUC to acquire a portion of Santee Cooper’s ownership interest in the New Units.  Similarly, Santee Cooper announced in July 2011 that it has entered into separate letters of intent with Duke and FMPA that may result in either or both of them acquiring a portion of Santee Cooper’s ownership interest in the New Units.  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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SEGMENT OF BUSINESS INFORMATION - SCEG

6 Months Ended

Jun. 30, 2011

SEGMENT OF BUSINESS INFORMATION

10.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 and Gas Distribution 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.  Nonreportable segments include a FERC-regulated interstate pipeline company and other companies that conduct nonregulated operations in energy-related and telecommunications industries.

	External			Intersegment			Operating			Income Available to			Segment
Millions of dollars	Revenue			Revenue			Income			Common Shareholders			Assets
Three Months Ended June 30, 2011
Electric Operations	$	616		$	2		$	140			n/a
Gas Distribution		132			-			2			n/a
Retail Gas Marketing		78			-			n/a		$	(3	)
Energy Marketing		172			52			n/a			1
All Other		10			104			3			-
Adjustments/Eliminations		(8	)		(158	)		(3	)		58
Consolidated Total	$	1,000		$	-		$	142		$	56
Six Months Ended June 30, 2011
Electric Operations	$	1,174		$	4		$	262			n/a		$	8,108
Gas Distribution		492			-			86			n/a			2,178
Retail Gas Marketing		280			-			n/a		$	19			178
Energy Marketing		330			97			n/a			2			123
All Other		20			206			8			1			1,287
Adjustments/Eliminations		(15	)		(307	)		34			162			1,270
Consolidated Total	$	2,281		$	-		$	390		$	184		$	13,144

	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
Retail Gas Marketing		74			-			n/a		$	(5	)
Energy Marketing		153			42			n/a			2
All Other		10			105			5			(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
Retail Gas Marketing		336			-			n/a		$	24			157
Energy Marketing		349			89			n/a			2			116
All Other		18			202			10			(6	)		1,206
Adjustments/Eliminations		(13	)		(295	)		40			160			1,168
Consolidated Total	$	2,367		$	-		$	367		$	180		$	12,252

SOUTH CAROLINA ELECTRIC AND GAS COMPANY

SEGMENT OF BUSINESS INFORMATION

11. 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.

			Operating			Earnings Available
	External		Income			to Common		Segment
Millions of Dollars	Revenue		(Loss)			Shareholder		Assets
Three Months Ended June 30, 2011
Electric Operations	$	618	$	140		n/a
Gas Distribution	73		(2		)	n/a
Adjustments/Eliminations	-		(1		)	$	59
Consolidated Total	$	691	$	137		$	59
Six Months Ended June 30, 2011
Electric Operations	$	1,178	$	262		n/a		$	8,107
Gas Distribution	218		28			n/a		597
Adjustments/Eliminations	-		(1		)	$	127	2,071
Consolidated Total	$	1,396	$	289		$	127	$	10,775
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

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RATE AND OTHER REGULATORY MATTERS - SCEG

6 Months Ended

Jun. 30, 2011

RATE AND OTHER REGULATORY MATTERS

2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G’s retail electric rates are established in part by 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 until May 2011.  SCE&G is allowed to charge and accrue carrying costs monthly on the actual base fuel costs undercollected balance as of the end of each month during this deferral period.  In February 2011, SCE&G requested authorization to increase the cost of fuel component of its retail electric rates to be effective with the first billing cycle of May 2011.  On March 17, 2011, SCE&G, ORS and SCEUC entered into a settlement agreement in which SCE&G agreed to recover its actual base fuel under-collected balance as of April 30, 2011 over a two year period commencing with the first billing cycle of May 2011.  The settlement agreement also provided that SCE&G would be allowed to charge and accrue carrying costs monthly on the deferred balance.  By order dated April 26, 2011, the SCPSC approved the settlement agreement and authorized SCE&G to adjust the cost of fuel component of its retail electric rates effective with the first billing cycle of May 2011.

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 (1) included implementation of an eWNA for SCE&G’s electric customers, which began in August 2010, (2) provided for a $25 million credit, over one year, to SCE&G’s customers to be offset by amortization of weather-related revenues which were deferred in the first quarter of 2010 pursuant to a stipulation between SCE&G and the ORS, (3) provided for a $48.7 million credit to SCE&G’s customers over two years to be offset by accelerated recognition of previously deferred state income tax credits and (4) 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. On July 27, 2010, SCE&G filed the rate rider tariff sheet for DSM Programs with the SCPSC. The tariff rider was applied to bills rendered on or after October 30, 2010. The order requires that SCE&G submit annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentive and net program benefits.  In January 2011, SCE&G submitted to the SCPSC its annual update on DSM Programs.  Included in the filing was a petition to update the rate rider to provide for the recovery of costs, lost net margin revenue, and the approved shared savings incentive for investing in such DSM Programs.  By order dated May 24, 2011, the SCPSC approved the updated rate rider and authorized SCE&G to increase its rates for DSM Programs as set forth in its petition.

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. This initial request, if approved, would result in an annual revenue increase of approximately $5.6 million. On February 26, 2010, the FERC accepted SCE&G’s initial filing and set the filing for hearing and settlement procedures.  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 12, 2011, SCE&G filed a motion to implement interim rates pending FERC action on a full settlement agreement, which the Chief Administrative Law Judge granted on May 13, 2011. On the same day, SCE&G filed a full settlement agreement.  As required by SCE&G’s protocols, on May 16, 2011, SCE&G submitted to the FERC as an informational filing its recalculated Annual Transmission Revenue Requirement or “Annual Update” which conforms to the settlement agreement, effective for the period June 1, 2011 through May 31, 2012.  The settlement agreement was certified as an uncontested settlement on June 30, 2011 and is pending final consideration by FERC.

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 the New 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.

In May 2009, two intervenors filed separate appeals of the order 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 reversed the SCPSC’s decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G’s share of the project, as originally approved by the SCPSC, is $4.5 billion in 2007 dollars. Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court’s ruling, however, does not affect the project schedule or disturb the SCPSC’s issuance of a certificate of environmental compatibility and public convenience and necessity, which is required to construct the New Units. On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule that reflects the removal of the contingency reserve and incorporates presently identifiable capital costs of $173.9 million, and by order dated May 16, 2011, the SCPSC approved the updated capital costs schedule as  outlined in the petition.

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. In October 2010, the SCPSC approved an increase of $47.3 million or 2.3%, under the BLRA for the annual revised rates adjustment filing. The new retail electric rates were effective for bills rendered on and after October 30, 2010.  On May 27, 2011, SCE&G filed with the SCPSC its annual request for revised rates under the BLRA seeking authorization to revise its retail electric rates so as to recover the costs of capital associated with the construction of the new nuclear units during the 12 months ended June 30, 2011.  If approved, SCE&G expects this request will constitute a $58.5 million or 2.7% increase to retail electric rates effective for bills rendered on or after October 30, 2011.

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 October 15, 2010, pursuant to the annual RSA filing, the SCPSC approved a decrease in retail natural gas rates of $10.4 million or approximately 2.1%.  The rate adjustment was effective with the first billing cycle of November 2010.  On June 15, 2011, SCE&G filed an application with the SCPSC requesting an increase in retail natural gas rates of $8.64 million or 2.14% under the terms of the RSA.  If approved, the new rates would become effective with the first billing cycle of November 2011.

SCE&G’s natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities. SCE&G’s gas rates are calculated using a methodology which adjusts the cost of gas monthly based on a 12-month rolling average. The annual PGA hearing to review SCE&G’s gas purchasing policies and procedures was conducted in November 2010, before the SCPSC. The SCPSC issued an order in December 2010 finding that SCE&G’s gas purchasing policies and practices during the review period of August 1, 2009, through July 31, 2010, were reasonable and prudent.  The next annual PGA hearing before the SCPSC has been scheduled for November 10, 2011.

In February 2011, the ORS submitted a request to the SCPSC to suspend SCE&G’s natural gas hedging program.  SCE&G responded in March 2011 indicating no objection to the ORS’s request.  The SCPSC issued an order directing staff to schedule an Oral Argument Information Briefing regarding this matter, which was held in April 2011.  In May 2011, the SCPSC directed its staff to schedule a hearing so that the SCPSC could receive testimony from electric and gas utilities concerning the market for natural gas and the need for natural gas hedging.  In June 2011, the ORS withdrew its petition requesting that the SCPSC suspend SCE&G’s natural gas hedging program.

PSNC Energy

PSNC Energy is subject to a Rider D rate mechanism which allows it to recover from customers all prudently incurred gas costs and certain uncollectible expenses related to gas cost.  The Rider D rate mechanism also allows PSNC Energy to recover, in any manner authorized by the NCUC, losses on negotiated gas and transportation sales.

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 semi-annually for residential and commercial customers based on average per customer consumption.

In October 2010, in connection with PSNC Energy’s 2010 Annual Prudence Review, the NCUC determined that PSNC Energy’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2010.

CGT

On April 29, 2011 CGT filed for a rate increase with the FERC.  The filing was in the form of a settlement agreement negotiated by CGT and its customers.  On July 5, 2011 the FERC approved the settlement agreement with minimal changes. The order approved the new rates to be effective November 1, 2011, as requested.

Regulatory Assets and Regulatory Liabilities

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	2011		2010
Regulatory Assets:
Accumulated deferred income taxes	$	210	$	210
Under-collections - electric fuel adjustment clause	59		25
Environmental remediation costs	31		32
AROs and related funding	310		298
Franchise agreements	42		45
Deferred employee benefit plan costs	321		326
Planned major maintenance	19		6
Deferred losses on interest rate derivatives	90		83
Other	46		36
Total Regulatory Assets	$	1,128	$	1,061
Regulatory Liabilities:
Accumulated deferred income taxes	$	25	$	26
Asset removal costs	804		780
Storm damage reserve	36		38
Monetization of bankruptcy claim	36		37
Deferred gains on interest rate derivatives	25		26
Other	5		6
Total Regulatory Liabilities	$	931	$	913

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 July 2012 through April 2013.  SCE&G is allowed to accrue interest on the 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 the Company.  These regulatory assets are expected to be recovered over periods of up to approximately 18 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, although recovery periods could become longer at the direction of the SCPSC.

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 pursuant to specific SCPSC orders.  SCE&G collected $8.5 million annually through July 15, 2010, through electric rates, to offset turbine maintenance expenditures.  After July 15, 2010, SCE&G began collecting $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 derivatives 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 approximately 30 years.

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, 2011 and 2010, SCE&G applied costs of $1.8 million and $1.5 million, respectively, to the reserve.  Pursuant to the SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended collection of storm damage reserve funds indefinitely, pending future SCPSC action.

The monetization of bankruptcy claim represents proceeds from the sale of a bankruptcy claim which are expected to be amortized into operating revenue through February 2024.

The SCPSC, the NCUC or the FERC have reviewed and approved through specific orders most of the items shown as regulatory assets.   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.

SOUTH CAROLINA ELECTRIC AND GAS COMPANY

RATE AND OTHER REGULATORY MATTERS

2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G’s retail electric rates are established in part, by 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 until May 2011.  SCE&G is allowed to charge and accrue carrying costs monthly on the actual base fuel costs undercollected balance as of the end of each month during this deferral period.  In February 2011, SCE&G requested authorization to increase the cost of fuel component of its retail electric rates to be effective with the first billing cycle of May 2011.  On March 17, 2011, SCE&G, ORS and SCEUC entered into a settlement agreement in which SCE&G agreed to recover its actual base fuel under-collected balance as of April 30, 2011 over a two year period commencing with the first billing cycle of May 2011.  The settlement agreement also provided that SCE&G would be allowed to charge and accrue carrying costs monthly on the deferred balance.  By order dated April 26, 2011, the SCPSC approved the settlement agreement and authorized SCE&G to adjust the cost of fuel component of its retail electric rates effective with the first billing cycle of May 2011.

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 (1) included implementation of an eWNA for SCE&G’s electric customers, which began in August 2010, (2) provided for a $25 million credit, over one year, to SCE&G’s customers to be offset by amortization of weather-related revenues which were deferred in the first quarter of 2010 pursuant to a stipulation between SCE&G and the ORS, (3) provided for a $48.7 million credit to SCE&G’s customers over two years to be offset by accelerated recognition of previously deferred state income tax credits and (4) 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. On July 27, 2010, SCE&G filed the rate rider tariff sheet for DSM Programs with the SCPSC. The tariff rider was applied to bills rendered on or after October 30, 2010. The order requires that SCE&G submit annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentive and net program benefits.  In January 2011, SCE&G submitted to the SCPSC its annual update on DSM Programs.  Included in the filing was a petition to update the rate rider to provide for the recovery of costs, lost net margin revenue, and the approved shared savings incentive for investing in such DSM Programs.  By order dated May 24, 2011, the SCPSC approved the updated rate rider and authorized SCE&G to increase its rates for DSM Programs as set forth in its petition.

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. This initial request, if approved, would result in an annual revenue increase of approximately $5.6 million. On February 26, 2010, the FERC accepted SCE&G’s initial filing and set the filing for hearing and settlement procedures.  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 12, 2011, SCE&G filed a motion to implement interim rates pending FERC action on a full settlement agreement, which the Chief Administrative Law Judge granted on May 13, 2011. On the same day, SCE&G filed a full settlement agreement.  As required by SCE&G’s protocols, on May 16, 2011, SCE&G submitted to the FERC as an informational filing its recalculated Annual Transmission Revenue Requirement or “Annual Update” which conforms to the settlement agreement, effective for the period June 1, 2011 through May 31, 2012.  The settlement agreement was certified as an uncontested settlement on June 30, 2011 and is pending final consideration by FERC.

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 the New 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.

In May 2009, two intervenors filed separate appeals of the order 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 reversed the SCPSC’s decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G’s share of the project, as originally approved by the SCPSC, is $4.5 billion in 2007 dollars.  Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs.  The Court’s ruling, however, does not affect the project schedule or disturb the SCPSC’s issuance of a certificate of environmental compatibility and public convenience and necessity, which is required to construct the New Units.  On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule that reflects the removal of the contingency reserve and incorporates presently identifiable capital costs of $173.9 million, and by order dated May 16, 2011, the SCPSC approved the updated capital costs schedule as outlined in the petition.

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. In October 2010, the SCPSC approved an increase of $47.3 million or 2.3%, under the BLRA for the annual revised rates adjustment filing.  The new retail electric rates were effective for bills rendered on and after October 30, 2010.  On May 27, 2011, SCE&G filed with the SCPSC its annual request for revised rates under the BLRA seeking authorization to revise its retail electric rates so as to recover the costs of capital associated with the construction of the new nuclear units during the 12 months ended June 30, 2011.  If approved, SCE&G expects this request will constitute a $58.5 million of 2.7% increase to retail electric rates effective for bills rendered on and after October 30, 2011.

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 October 15, 2010, pursuant to the annual RSA filing, the SCPSC approved a decrease in retail natural gas rates of $10.4 million or approximately 2.1%.  The rate adjustment was effective with the first billing cycle of November 2010.  On June 15, 2011, SCE&G filed an application with the SCPSC requesting an increase in retail natural gas rates of $8.64 million or 2.14% under the terms of the RSA.  If approved, the new rates would become effective with the first billing cycle of November 2011.

SCE&G’s natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities. SCE&G’s gas rates are calculated using a methodology which adjusts the cost of gas monthly based on a 12-month rolling average. The annual PGA hearing to review SCE&G’s gas purchasing policies and procedures was conducted in November 2010, before the SCPSC. The SCPSC issued an order in December 2010 finding that SCE&G’s gas purchasing policies and practices during the review period of August 1, 2009, through July 31, 2010, were reasonable and prudent.  The next annual PGA hearing before the SCPSC has been scheduled for November 10, 2011.

In February 2011, the ORS submitted a request to the SCPSC to suspend SCE&G’s natural gas hedging program.  SCE&G responded in March 2011 indicating no objection to the ORS’s request.  The SCPSC issued an order directing staff to schedule an Oral Argument Information Briefing regarding this matter, which was held in April 2011.  In May 2011, the SCPSC directed its staff to schedule a hearing so that the SCPSC could receive testimony from electric and gas utilities concerning the market for natural gas and the need for natural gas hedging.  In June 2011, the ORS withdrew its petition requesting that the SCPSC suspend SCE&G’s natural gas hedging program.

Regulatory Assets and Regulatory Liabilities

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	2011		2010
Regulatory Assets:
Accumulated deferred income taxes	$	205	$	205
Under collections – electric fuel adjustment clause	59		25
Environmental remediation costs	26		27
AROs and related funding	296		284
Franchise agreements	42		45
Deferred employee benefit plan costs	285		288
Planned major maintenance	19		6
Deferred losses on interest rate derivatives	90		83
Other	43		33
Total Regulatory Assets	$	1,065	$	996

Regulatory Liabilities:
Accumulated deferred income taxes	$	24	$	26
Asset removal costs	585		568
Storm damage reserve	36		38
Deferred gains on interest rate derivatives	25		26
Other	5		4
Total Regulatory Liabilities	$	675	$	662

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 July 2012 through April 2013.  SCE&G is allowed to accrue interest on the 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 18 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, although recovery periods could become longer at the direction of the SCPSC.

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 pursuant to specific SCPSC orders.  SCE&G collected $8.5 million annually through July 15, 2010, through electric rates, to offset turbine maintenance expenditures.  After July 15, 2010, SCE&G began collecting $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 derivatives 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 approximately 30 years.

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, 2011 and 2010, SCE&G applied costs of $1.8 million and $1.5 million, respectively, to the reserve.  Pursuant to the SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended collection of the storm damage reserve indefinitely, pending future SCPSC action.

The SCPSC or the FERC have reviewed and approved through specific orders most of the items shown as regulatory assets.   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.

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RATE AND OTHER REGULATORY MATTERS

6 Months Ended

Jun. 30, 2011

RATE AND OTHER REGULATORY MATTERS

RATE AND OTHER REGULATORY MATTERS

2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G’s retail electric rates are established in part by 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 until May 2011.  SCE&G is allowed to charge and accrue carrying costs monthly on the actual base fuel costs undercollected balance as of the end of each month during this deferral period.  In February 2011, SCE&G requested authorization to increase the cost of fuel component of its retail electric rates to be effective with the first billing cycle of May 2011.  On March 17, 2011, SCE&G, ORS and SCEUC entered into a settlement agreement in which SCE&G agreed to recover its actual base fuel under-collected balance as of April 30, 2011 over a two year period commencing with the first billing cycle of May 2011.  The settlement agreement also provided that SCE&G would be allowed to charge and accrue carrying costs monthly on the deferred balance.  By order dated April 26, 2011, the SCPSC approved the settlement agreement and authorized SCE&G to adjust the cost of fuel component of its retail electric rates effective with the first billing cycle of May 2011.

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 (1) included implementation of an eWNA for SCE&G’s electric customers, which began in August 2010, (2) provided for a $25 million credit, over one year, to SCE&G’s customers to be offset by amortization of weather-related revenues which were deferred in the first quarter of 2010 pursuant to a stipulation between SCE&G and the ORS, (3) provided for a $48.7 million credit to SCE&G’s customers over two years to be offset by accelerated recognition of previously deferred state income tax credits and (4) 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. On July 27, 2010, SCE&G filed the rate rider tariff sheet for DSM Programs with the SCPSC. The tariff rider was applied to bills rendered on or after October 30, 2010. The order requires that SCE&G submit annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentive and net program benefits.  In January 2011, SCE&G submitted to the SCPSC its annual update on DSM Programs.  Included in the filing was a petition to update the rate rider to provide for the recovery of costs, lost net margin revenue, and the approved shared savings incentive for investing in such DSM Programs.  By order dated May 24, 2011, the SCPSC approved the updated rate rider and authorized SCE&G to increase its rates for DSM Programs as set forth in its petition.

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. This initial request, if approved, would result in an annual revenue increase of approximately $5.6 million. On February 26, 2010, the FERC accepted SCE&G’s initial filing and set the filing for hearing and settlement procedures.  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 12, 2011, SCE&G filed a motion to implement interim rates pending FERC action on a full settlement agreement, which the Chief Administrative Law Judge granted on May 13, 2011. On the same day, SCE&G filed a full settlement agreement.  As required by SCE&G’s protocols, on May 16, 2011, SCE&G submitted to the FERC as an informational filing its recalculated Annual Transmission Revenue Requirement or “Annual Update” which conforms to the settlement agreement, effective for the period June 1, 2011 through May 31, 2012.  The settlement agreement was certified as an uncontested settlement on June 30, 2011 and is pending final consideration by FERC.

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 the New 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.

In May 2009, two intervenors filed separate appeals of the order 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 reversed the SCPSC’s decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G’s share of the project, as originally approved by the SCPSC, is $4.5 billion in 2007 dollars. Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court’s ruling, however, does not affect the project schedule or disturb the SCPSC’s issuance of a certificate of environmental compatibility and public convenience and necessity, which is required to construct the New Units. On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule that reflects the removal of the contingency reserve and incorporates presently identifiable capital costs of $173.9 million, and by order dated May 16, 2011, the SCPSC approved the updated capital costs schedule as  outlined in the petition.

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. In October 2010, the SCPSC approved an increase of $47.3 million or 2.3%, under the BLRA for the annual revised rates adjustment filing. The new retail electric rates were effective for bills rendered on and after October 30, 2010.  On May 27, 2011, SCE&G filed with the SCPSC its annual request for revised rates under the BLRA seeking authorization to revise its retail electric rates so as to recover the costs of capital associated with the construction of the new nuclear units during the 12 months ended June 30, 2011.  If approved, SCE&G expects this request will constitute a $58.5 million or 2.7% increase to retail electric rates effective for bills rendered on or after October 30, 2011.

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 October 15, 2010, pursuant to the annual RSA filing, the SCPSC approved a decrease in retail natural gas rates of $10.4 million or approximately 2.1%.  The rate adjustment was effective with the first billing cycle of November 2010.  On June 15, 2011, SCE&G filed an application with the SCPSC requesting an increase in retail natural gas rates of $8.64 million or 2.14% under the terms of the RSA.  If approved, the new rates would become effective with the first billing cycle of November 2011.

SCE&G’s natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities. SCE&G’s gas rates are calculated using a methodology which adjusts the cost of gas monthly based on a 12-month rolling average. The annual PGA hearing to review SCE&G’s gas purchasing policies and procedures was conducted in November 2010, before the SCPSC. The SCPSC issued an order in December 2010 finding that SCE&G’s gas purchasing policies and practices during the review period of August 1, 2009, through July 31, 2010, were reasonable and prudent.  The next annual PGA hearing before the SCPSC has been scheduled for November 10, 2011.

In February 2011, the ORS submitted a request to the SCPSC to suspend SCE&G’s natural gas hedging program.  SCE&G responded in March 2011 indicating no objection to the ORS’s request.  The SCPSC issued an order directing staff to schedule an Oral Argument Information Briefing regarding this matter, which was held in April 2011.  In May 2011, the SCPSC directed its staff to schedule a hearing so that the SCPSC could receive testimony from electric and gas utilities concerning the market for natural gas and the need for natural gas hedging.  In June 2011, the ORS withdrew its petition requesting that the SCPSC suspend SCE&G’s natural gas hedging program.

PSNC Energy

PSNC Energy is subject to a Rider D rate mechanism which allows it to recover from customers all prudently incurred gas costs and certain uncollectible expenses related to gas cost.  The Rider D rate mechanism also allows PSNC Energy to recover, in any manner authorized by the NCUC, losses on negotiated gas and transportation sales.

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 semi-annually for residential and commercial customers based on average per customer consumption.

In October 2010, in connection with PSNC Energy’s 2010 Annual Prudence Review, the NCUC determined that PSNC Energy’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2010.

CGT

On April 29, 2011 CGT filed for a rate increase with the FERC.  The filing was in the form of a settlement agreement negotiated by CGT and its customers.  On July 5, 2011 the FERC approved the settlement agreement with minimal changes. The order approved the new rates to be effective November 1, 2011, as requested.

Regulatory Assets and Regulatory Liabilities

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	2011		2010
Regulatory Assets:
Accumulated deferred income taxes	$	210	$	210
Under-collections - electric fuel adjustment clause	59		25
Environmental remediation costs	31		32
AROs and related funding	310		298
Franchise agreements	42		45
Deferred employee benefit plan costs	321		326
Planned major maintenance	19		6
Deferred losses on interest rate derivatives	90		83
Other	46		36
Total Regulatory Assets	$	1,128	$	1,061
Regulatory Liabilities:
Accumulated deferred income taxes	$	25	$	26
Asset removal costs	804		780
Storm damage reserve	36		38
Monetization of bankruptcy claim	36		37
Deferred gains on interest rate derivatives	25		26
Other	5		6
Total Regulatory Liabilities	$	931	$	913

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 July 2012 through April 2013.  SCE&G is allowed to accrue interest on the 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 the Company.  These regulatory assets are expected to be recovered over periods of up to approximately 18 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, although recovery periods could become longer at the direction of the SCPSC.

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 pursuant to specific SCPSC orders.  SCE&G collected $8.5 million annually through July 15, 2010, through electric rates, to offset turbine maintenance expenditures.  After July 15, 2010, SCE&G began collecting $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 derivatives 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 approximately 30 years.

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, 2011 and 2010, SCE&G applied costs of $1.8 million and $1.5 million, respectively, to the reserve.  Pursuant to the SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended collection of storm damage reserve funds indefinitely, pending future SCPSC action.

The monetization of bankruptcy claim represents proceeds from the sale of a bankruptcy claim which are expected to be amortized into operating revenue through February 2024.

The SCPSC, the NCUC or the FERC have reviewed and approved through specific orders most of the items shown as regulatory assets.   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.

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CONDENSED CONSOLIDATED BALANCE SHEETS - SCEG (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Assets
Utility Plant In Service	$ 11,901	$ 11,714
Accumulated Depreciation and Amortization	(3,599)	(3,495)
Construction Work in Progress	1,284	1,081
Nuclear Fuel, Net of Accumulated Amortization	133	132
Utility Plant, Net	9,949	9,662
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	302	299
Assets held in trust, net - nuclear decommissioning	80	76
Other investments	87	78
Nonutility Property and Investments, Net	469	453
Current Assets:
Cash and cash equivalents	166	55
Receivables, net of allowance for uncollectible accounts of $3 and $3	627	837
Inventories (at average cost):
Fuel and gas supply	284	316
Materials and supplies	128	125
Emission allowances	4	6
Prepayments and other	207	271
Deferred income taxes	19	21
Total Current Assets	1,435	1,631
Deferred Debits and Other Assets:
Regulatory assets	1,128.0	1,061.0
Other	163	161
Total Deferred Debits and Other Assets	1,291	1,222
Total	13,144	12,968
Capitalization and Liabilities
Common equity	3,805	3,702
Long-Term Debt, net	4,379	4,152
Total Capitalization	8,184	7,854
Current Liabilities:
Short-term borrowings	546	420
Current portion of long-term debt	286	337
Accounts Payable	379	526
Customer deposits and customer prepayments	96	100
Taxes accrued	83	146
Interest accrued	74	72
Dividends declared	63	61
Derivative financial instruments	20	65
Other	106	140
Total Current Liabilities	1,653	1,867
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,429	1,391
Deferred investment tax credits	43	56
Asset retirement obligations	510	497
Other postretirement benefits	205	202
Regulatory liabilities	931	913
Other	189	188
Total Deferred Credits and Other Liabilities	3,307	3,247
Commitments and Contingencies (Note 9)
Total	13,144	12,968
SOUTH CAROLINA ELECTRIC AND GAS COMPANY
Assets
Utility Plant In Service	10,244	10,112
Accumulated Depreciation and Amortization	(3,188)	(3,098)
Construction Work in Progress	1,269	1,051
Nuclear Fuel, Net of Accumulated Amortization	133	133
Utility Plant, Net	8,458	8,198
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	51	46
Assets held in trust, net - nuclear decommissioning	80	76
Other investments	4	4
Nonutility Property and Investments, Net	135	126
Current Assets:
Cash and cash equivalents	28	31
Receivables, net of allowance for uncollectible accounts of $3 and $3	444	507
Inventories (at average cost):
Fuel and gas supply	192	216
Materials and supplies	118	117
Emission allowances	4	6
Prepayments and other	121	168
Deferred income taxes	15	15
Total Current Assets	922	1,060
Deferred Debits and Other Assets:
Pension asset	59	57
Regulatory assets	1,065.0	996.0
Other	136	137
Total Deferred Debits and Other Assets	1,260	1,190
Total	10,775	10,574
Capitalization and Liabilities
Common equity	3,516	3,436
Noncontrolling interest	106	105
Long-Term Debt, net	3,227	3,037
Total Capitalization	6,849	6,578
Current Liabilities:
Short-term borrowings	475	381
Current portion of long-term debt	22	22
Accounts Payable	229	341
Affiliated Payables	145	140
Customer deposits and customer prepayments	57	60
Taxes accrued	78	137
Interest accrued	54	50
Dividends declared	49	54
Derivative financial instruments		34
Other	59	80
Total Current Liabilities	1,168	1,299
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,276	1,240
Deferred investment tax credits	42	56
Asset retirement obligations	490	478
Other postretirement benefits	163	163
Regulatory liabilities	675	662
Other	112	98
Total Deferred Credits and Other Liabilities	2,758	2,697
Commitments and Contingencies (Note 9)
Total	$ 10,775	$ 10,574

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RATE AND OTHER REGULATORY MATTERS (Details) (SCE&G, USD $)	1 Months Ended								6 Months Ended
	Oct. 30, 2011	Jun. 30, 2011	Apr. 30, 2011	Oct. 31, 2010	Jul. 31, 2010	Jan. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Jun. 30, 2011	May 31, 2009	Dec. 31, 2007
SCE&G
Rate Matters
Recognized amount of fuel costs previously deferred as state income tax credits		$ 17,400,000							$ 17,400,000
Base fuel undercollected balance, recovery period (in years)			2
Increase in retail electric rates (as a percent)	2.70%			2.30%	4.88%			1.10%
Allowable return on common equity (as a percent)					10.70%				11.00%
Stipulations adopted pertaining to the order issued					1) included implementation of an eWNA for SCE&G's electric customers, which began in August 2010, (2) provided for a $25 million credit, over one year, to SCE&G's customers to be offset by amortization of weather related revenues which were deferred in the first quarter of 2010 pursuant to a stipulation between SCE&G and the ORS, (3) provided for a $48.7 million credit to SCE&G's customers over two years to be offset by accelerated recognition of previously deferred state income tax credits and (4) provided for the recovery of certain federally mandated capital expenditures that had been included in utility plant but were not being depreciated.
Credit to customers to be offset by amortization of weather-related revenues					25,000,000
Length of credit period (in years)					1Y
Credit to customers to be offset by accelerated recognition of previously deferred state income tax credits					48,700,000
Length of credit period (in years)					2Y
Estimated increase in revenue subject to change in the network and point to point transmission rates							5,600,000
Number of new nuclear generating units at summer station						2
Increase in retail electric rates	58,500,000			47,300,000				22,500,000
Number of intervenors who filed separate appeals to challenge the order passed by the regulatory authority										2
Amount of approved cost allowed as capital costs											4,500,000,000
Contingency cost associated with the project									438,000,000
Identifiable capital costs after approval of updated capital cost schedule									173,900,000
Increase (decrease) in natural gas retail rates				(10,400,000)
Increase (decrease) in natural gas retail rate requested		$ 8,640,000
Percentage increase (decrease) in natural gas retail rates (as a percent)				(2.10%)
Percentage increase (decrease) in natural gas retail rate requested (as a percent)		2.14%
Basis for rate calculation									12-month rolling average

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INCOME TAXES (Details) (USD $) In Millions	6 Months Ended
	Jun. 30, 2011
Income Taxes
Unrecognized tax benefit	$ 36
Possible increase in unrecognized tax benefit	12
Possible decrease in unrecognized tax benefit	36
Accrued interest expense	$ 0.8

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SEGMENT OF BUSINESS INFORMATION (Details) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Segment reporting information
External Revenue	$ 1,000	$ 939	$ 2,281	$ 2,367
Operating Income	142	137	390	367
Income Available to Common Shareholders	56	54	184	180
Segment Assets	13,144	12,252	13,144	12,252	12,968
Electric Operations
Segment reporting information
External Revenue	616	575	1,174	1,115
Intersegment Revenue	2	2	4	4
Operating Income	140	139	262	225
Segment Assets	8,108	7,545	8,108	7,545
Gas Distribution
Segment reporting information
External Revenue	132	134	492	562
Operating Income	2	2	86	92
Segment Assets	2,178	2,060	2,178	2,060
Retail Gas Marketing
Segment reporting information
External Revenue	78	74	280	336
Income Available to Common Shareholders	(3)	(5)	19	24
Segment Assets	178	157	178	157
Energy Marketing
Segment reporting information
External Revenue	172	153	330	349
Intersegment Revenue	52	42	97	89
Income Available to Common Shareholders	1	2	2	2
Segment Assets	123	116	123	116
All Other
Segment reporting information
External Revenue	10	10	20	18
Intersegment Revenue	104	105	206	202
Operating Income	3	5	8	10
Income Available to Common Shareholders		(6)	1	(6)
Segment Assets	1,287	1,206	1,287	1,206
Adjustments/Eliminations
Segment reporting information
External Revenue	(8)	(7)	(15)	(13)
Intersegment Revenue	(158)	(149)	(307)	(295)
Operating Income	(3)	(9)	34	40
Income Available to Common Shareholders	58	63	162	160
Segment Assets	$ 1,270	$ 1,168	$ 1,270	$ 1,168

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RATE AND OTHER REGULATORY MATTERS (Details 3) (USD $) In Millions			6 Months Ended						6 Months Ended
	Jun. 30, 2011	Dec. 31, 2010	Jun. 30, 2011 SCE&G Storm damage reserve	Jun. 30, 2010 SCE&G Storm damage reserve	Jun. 30, 2011 Accumulated deferred income taxes	Dec. 31, 2010 Accumulated deferred income taxes	Jun. 30, 2011 Asset removal costs	Dec. 31, 2010 Asset removal costs	Jun. 30, 2011 Storm damage reserve	Dec. 31, 2010 Storm damage reserve	Jun. 30, 2011 Monetization of bankruptcy claim	Dec. 31, 2010 Monetization of bankruptcy claim	Jun. 30, 2011 Deferred gains on interest rate derivatives	Dec. 31, 2010 Deferred gains on interest rate derivatives	Jun. 30, 2011 Other	Dec. 31, 2010 Other
Regulatory Liabilities:
Regulatory liabilities	$ 931	$ 913			$ 25	$ 26	$ 804	$ 780	$ 36	$ 38	$ 36	$ 37	$ 25	$ 26	$ 5	$ 6
Amount recovered through electric rates to offset incremental storm damage costs									100
Excess amount of storm damage costs which can be offset by amounts recovered through electric rates									2.5
Cost applied to storm damage cost reserve			$ 1.8	$ 1.5

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SEGMENT OF BUSINESS INFORMATION

6 Months Ended

Jun. 30, 2011

SEGMENT OF BUSINESS INFORMATION

SEGMENT OF BUSINESS INFORMATION

10.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 and Gas Distribution 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.  Nonreportable segments include a FERC-regulated interstate pipeline company and other companies that conduct nonregulated operations in energy-related and telecommunications industries.

	External			Intersegment			Operating			Income Available to			Segment
Millions of dollars	Revenue			Revenue			Income			Common Shareholders			Assets
Three Months Ended June 30, 2011
Electric Operations	$	616		$	2		$	140			n/a
Gas Distribution		132			-			2			n/a
Retail Gas Marketing		78			-			n/a		$	(3	)
Energy Marketing		172			52			n/a			1
All Other		10			104			3			-
Adjustments/Eliminations		(8	)		(158	)		(3	)		58
Consolidated Total	$	1,000		$	-		$	142		$	56
Six Months Ended June 30, 2011
Electric Operations	$	1,174		$	4		$	262			n/a		$	8,108
Gas Distribution		492			-			86			n/a			2,178
Retail Gas Marketing		280			-			n/a		$	19			178
Energy Marketing		330			97			n/a			2			123
All Other		20			206			8			1			1,287
Adjustments/Eliminations		(15	)		(307	)		34			162			1,270
Consolidated Total	$	2,281		$	-		$	390		$	184		$	13,144

	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
Retail Gas Marketing		74			-			n/a		$	(5	)
Energy Marketing		153			42			n/a			2
All Other		10			105			5			(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
Retail Gas Marketing		336			-			n/a		$	24			157
Energy Marketing		349			89			n/a			2			116
All Other		18			202			10			(6	)		1,206
Adjustments/Eliminations		(13	)		(295	)		40			160			1,168
Consolidated Total	$	2,367		$	-		$	367		$	180		$	12,252

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES - SCEG

6 Months Ended

Jun. 30, 2011

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

7. 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, 2011
Assets -	Available for sale securities	$	3	$	-
	Interest rate contracts		-		6
	Commodity contracts		2		2
	Energy management contracts		-		8
Liabilities -	Interest rate contracts		-		44
	Commodity contracts		1		4
	Energy management contracts		-		8
As of December 31, 2010
Assets -	Available for sale securities	$	3	$	-
	Interest rate contracts		-		8
	Commodity contracts		2		2
	Energy management contracts		-		9
Liabilities -	Interest rate contracts		-		82
	Commodity contracts		1		6
	Energy management contracts		-		11

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, 2011 and December 31, 2010 were as follows:

	June 30, 2011				December 31, 2010
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,664.9	$	5,016.2	$	4,488.3	$	4,840.5

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.

SOUTH CAROLINA ELECTRIC AND GAS COMPANY

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

SCE&G values commodity derivative assets and liabilities using unadjusted NYMEX prices to determine fair value, 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, 2011
Assets -	Interest rate contracts	$	-	$	3
	Commodity contracts		1		-
Liabilities-	Interest rate contracts		-		12
As of December 31, 2010
Assets -	Interest rate contracts	$	-	$	4
	Commodity contracts		1		-
Liabilities -	Interest rate contracts		-		35

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, 2011 and December 31, 2010 were as follows:

	June 30, 2011				December 31, 2010
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,249.4	$	3,517.0	$	3,059.7	$	3,321.8

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.

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Document and Entity Information	6 Months Ended
	Jun. 30, 2011	Jul. 27, 2011
Document and Entity Information
Entity Registrant Name	SCANA CORP
Entity Central Index Key	0000754737
Document Type	10-Q
Document Period End Date	Jun. 30, 2011
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		129,019,800
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q2

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COMMON EQUITY

6 Months Ended

Jun. 30, 2011

COMMON EQUITY

COMMON EQUITY

3. COMMON EQUITY

SCANA issued common stock valued at $50.1 million (at time of issue) during the six months ended June 30, 2011 through various compensation and dividend reinvestment plans (including the Stock Purchase Savings Plan), including the exercise of approximately 19,600 stock options during the period.  In addition, in May 2010 SCANA entered into forward sale contracts for approximately 6.6 million common shares to be settled no later than February 29, 2012.  There have been no shares issued under the forward sales contracts.

Authorized shares of common stock were 200 million as of June 30, 2011 and 150 million as of December 31, 2010.

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RATE AND OTHER REGULATORY MATTERS (Tables)

6 Months Ended

Jun. 30, 2011

RATE AND OTHER REGULATORY MATTERS

Summary of regulatory assets

	June 30,		December 31,
Millions of dollars	2011		2010
Regulatory Assets:
Accumulated deferred income taxes	$	210	$	210
Under-collections - electric fuel adjustment clause	59		25
Environmental remediation costs	31		32
AROs and related funding	310		298
Franchise agreements	42		45
Deferred employee benefit plan costs	321		326
Planned major maintenance	19		6
Deferred losses on interest rate derivatives	90		83
Other	46		36
Total Regulatory Assets	$	1,128	$	1,061

Summary of regulatory liabilities

Regulatory Liabilities:
Accumulated deferred income taxes	$	25	$	26
Asset removal costs	804		780
Storm damage reserve	36		38
Monetization of bankruptcy claim	36		37
Deferred gains on interest rate derivatives	25		26
Other	5		6
Total Regulatory Liabilities	$	931	$	913

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EMPLOYEE BENEFIT PLANS (Details) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Pension Benefits
Pension and Other Postretirement Benefit Plans
Service cost	$ 4.6	$ 4.8	$ 9.2	$ 9.5
Interest cost	11.1	11.9	22.2	23.7
Expected return on assets	(16.2)	(16.5)	(32.4)	(32.9)
Prior service cost amortization	1.8	1.8	3.6	3.7
Amortization of actuarial loss	3.0	4.3	6.0	8.6
Net periodic benefit cost	4.3	6.3	8.6	12.6
Other Postretirement Benefits
Pension and Other Postretirement Benefit Plans
Service cost	1.1	1.1	2.2	2.2
Interest cost	3.0	3.2	6.0	6.2
Prior service cost amortization	0.3	0.2	0.6	0.5
Transition obligation amortization	0.2	0.1	0.4	0.3
Amortization of actuarial loss	0.1	0.1	0.2	0.2
Net periodic benefit cost	4.7	4.7	9.4	9.4
SCE&G
Pension and Other Postretirement Benefit Plans
Pension costs allowable to be deferred as regulatory assets related to retail electric operations and natural gas operations	$ 2.3	$ 5.4	$ 4.6	$ 10.7

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RATE AND OTHER REGULATORY MATTERS (Details 2) (USD $) In Millions			1 Months Ended	6 Months Ended					6 Months Ended		6 Months Ended		6 Months Ended		6 Months Ended				6 Months Ended		6 Months Ended
	Jun. 30, 2011	Dec. 31, 2010	Jul. 31, 2010 SCE&G	Jun. 30, 2011 SCE&G	Jun. 30, 2011 Accumulated deferred income taxes	Dec. 31, 2010 Accumulated deferred income taxes	Jun. 30, 2011 Under-collections-electric fuel adjustment clause	Dec. 31, 2010 Under-collections-electric fuel adjustment clause	Jun. 30, 2011 Environmental remediation costs	Dec. 31, 2010 Environmental remediation costs	Jun. 30, 2011 Asset retirement obligations and related funding	Dec. 31, 2010 Asset retirement obligations and related funding	Jun. 30, 2011 Franchise agreements	Dec. 31, 2010 Franchise agreements	Jun. 30, 2011 Deferred employee benefit plan costs	Dec. 31, 2010 Deferred employee benefit plan costs	Jun. 30, 2011 Planned major maintenance	Dec. 31, 2010 Planned major maintenance	Jun. 30, 2011 Deferred losses on interest rate derivatives	Dec. 31, 2010 Deferred losses on interest rate derivatives	Jun. 30, 2011 Other.	Dec. 31, 2010 Other.
Regulatory Assets:
Regulatory assets	$ 1,128.0	$ 1,061.0			$ 210.0	$ 210.0	$ 59.0	$ 25.0	$ 31.0	$ 32.0	$ 310.0	$ 298.0	$ 42.0	$ 45.0	$ 321.0	$ 326.0	$ 19.0	$ 6.0	$ 90.0	$ 83.0	$ 46.0	$ 36.0
Regulatory assets, expected recovery period (in years)					70 years				18 years		95 years		20 years		14 years				30 years		30 years
Amount recovered through electric rates to offset turbine maintenance expenditures			$ 8.5	$ 18.4
Accrual period of nuclear refueling charges (in months)				18M

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Cash Flows From Operating Activities:
Net Income	$ 184	$ 180
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	45	116
Depreciation and amortization	173	174
Amortization of nuclear fuel	14	18
Allowance for equity funds used during construction	(8)	(10)
Carrying cost recovery		(3)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	210	100
Inventories	8	30
Prepayments and other	57	(19)
Regulatory liabilities	(6)	(3)
Accounts payable	(93)	(53)
Taxes accrued	(63)	(134)
Interest accrued	2	1
Regulatory assets	(28)	(90)
Changes in other assets	(12)	(8)
Changes in other liabilities	(59)	62
Net Cash Provided From Operating Activities	425	360
Cash Flows From Investing Activities:
Utility property additions and construction expenditures	(466)	(432)
Proceeds from investments	10	8
Nonutility property additions	(11)	(15)
Purchase of investments	(13)	(22)
Settlements of interest rate contracts	(61)
Net Cash Used For Investing Activities	(541)	(461)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock	50	106
Proceeds from issuance of long-term debt	796	203
Repayment of long-term debt	(623)	(67)
Dividends	(122)	(117)
Short-term borrowings, net	126	(104)
Net Cash Provided From (Used For) Financing Activities	227	21
Net Increase (Decrease) In Cash and Cash Equivalents	111	(80)
Cash and Cash Equivalents, January 1	55	162
Cash and Cash Equivalents, June 30	166	82
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $5 and $5)	134	132
Cash paid for - Income taxes		55
Noncash Investing and Financing Activities:
Accrued construction expenditures	125	95
Capital leases	$ 2	$ 6

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LONG-TERM DEBT AND LIQUIDITY (Tables)

6 Months Ended

Jun. 30, 2011

LONG-TERM DEBT AND LIQUIDITY

Schedule of line of credit facilities

		SCANA					SCE&G						PSNC Energy
		June 30,		December 31,			June 30,			December 31,			June 30,		December 31,
Millions of dollars		2011		2010			2011			2010			2011		2010
Lines of credit:
Committed long-term
Total	$	300		$	300		$	1,100		$	1,100		$	100	$	100
LOC advances		-		-			-			-			-		-
Weighted average interest rate		-		-			-			-			-		-
Outstanding commercial paper (270 or fewer days)	$	71		$	39		$	475		$	381		-		-
Weighted average interest rate		.35	%	.35		%	.35		%	.42		%	-		-
Letters of credit supported by LOC	$	3		$	3		$	.3		$	.3		-		-
Available	$	226		$	258		$	625		$	719		$	100	$	100

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME - SCEG (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Operating Revenues:
Electric	$ 616	$ 575	$ 1,174	$ 1,115
Gas	135	137	497	567
Total Operating Revenues	1,000	939	2,281	2,367
Operating Expenses:
Fuel used in electric generation	251	222	462	456
Purchased power	8	3	10	5
Gas purchased for resale	297	277	810	936
Other operation and maintenance	165	167	334	339
Depreciation and amortization	86	83	172	166
Other taxes	51	50	103	98
Total Operating Expenses	858	802	1,891	2,000
Operating Income	142	137	390	367
Other Income (Expense):
Other income	11	14	24	27
Other expenses	(9)	(9)	(19)	(19)
Interest charges, net of allowance for borrowed funds used during construction of $3, $3, $4 and $5	(70)	(66)	(139)	(131)
Allowance for equity funds used during construction	5	7	8	10
Total Other Expense	(63)	(54)	(126)	(113)
Income Before Income Tax Expense	79	83	264	254
Income Tax Expense	23	29	80	74
Income Available to Common Shareholders of SCANA	56	54	184	180
SOUTH CAROLINA ELECTRIC AND GAS COMPANY
Operating Revenues:
Electric	618	577	1,178	1,119
Gas	73	75	218	255
Total Operating Revenues	691	652	1,396	1,374
Operating Expenses:
Fuel used in electric generation	252	223	465	459
Purchased power	8	3	10	5
Gas purchased for resale	49	48	136	167
Other operation and maintenance	127	128	260	260
Depreciation and amortization	71	66	142	133
Other taxes	47	46	94	89
Total Operating Expenses	554	514	1,107	1,113
Operating Income	137	138	289	261
Other Income (Expense):
Other income	1	3	2	7
Other expenses	(3)	(4)	(7)	(7)
Interest charges, net of allowance for borrowed funds used during construction of $3, $3, $4 and $5	(50)	(46)	(100)	(93)
Allowance for equity funds used during construction	5	7	8	10
Total Other Expense	(47)	(40)	(97)	(83)
Income Before Income Tax Expense	90	98	192	178
Income Tax Expense	29	35	60	51
Net Income	61	63	132	127
Less Net Income Attributable to Noncontrolling Interest	2	3	5	5
Income Available to Common Shareholders of SCANA	59	60	127	122
Dividends Declared on Common Stock	$ 49	$ 47	$ 100	$ 94

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)

6 Months Ended

Jun. 30, 2011

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

Fair value measurements, and the level within the fair value hierarchy in which the measurements fall

		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, 2011
Assets -	Available for sale securities	$	3	$	-
	Interest rate contracts		-		6
	Commodity contracts		2		2
	Energy management contracts		-		8
Liabilities -	Interest rate contracts		-		44
	Commodity contracts		1		4
	Energy management contracts		-		8
As of December 31, 2010
Assets -	Available for sale securities	$	3	$	-
	Interest rate contracts		-		8
	Commodity contracts		2		2
	Energy management contracts		-		9
Liabilities -	Interest rate contracts		-		82
	Commodity contracts		1		6
	Energy management contracts		-		11

Financial instruments for which the carrying amount may not equal estimated fair value

	June 30, 2011				December 31, 2010
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,664.9	$	5,016.2	$	4,488.3	$	4,840.5

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010		Jun. 30, 2011		Jun. 30, 2010
Net Income	$ 56		$ 54		$ 184		$ 180
Other Comprehensive Income (Loss), net of tax:
Unrealized holding gains (losses) arising during period, net	(15)		(29)		(13)		(40)
Reclassified to net income:
Losses on cash flow hedging activities	1		4		6		9
Amortization of deferred employee benefit plan costs, net of taxes							1
Comprehensive income attributable to SCANA Corporation	$ 42	[1]	$ 29	[1]	$ 177	[1]	$ 150	[1]

[1] Accumulated other comprehensive loss totaled $53.2 million as of June 30, 2011 and $46.6 million as of December 31, 2010.

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EMPLOYEE BENEFIT PLANS

6 Months Ended

Jun. 30, 2011

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS

8. EMPLOYEE BENEFIT PLANS

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	2011			2010			2011		2010
Three months ended June 30,
Service cost	$	4.6		$	4.8		$	1.1	$	1.1
Interest cost	11.1			11.9			3.0		3.2
Expected return on assets	(16.2		)	(16.5		)	-		-
Prior service cost amortization	1.8			1.8			0.3		0.2
Transition obligation amortization	-			-			0.2		0.1
Amortization of actuarial loss	3.0			4.3			0.1		0.1
Net periodic benefit cost	$	4.3		$	6.3		$	4.7	$	4.7
Six months ended June 30,
Service cost	$	9.2		$	9.5		$	2.2	$	2.2
Interest cost	22.2			23.7			6.0		6.2
Expected return on assets	(32.4		)	(32.9		)	-		-
Prior service cost amortization	3.6			3.7			0.6		0.5
Transition obligation amortization	-			-			0.4		0.3
Amortization of actuarial loss	6.0			8.6			0.2		0.2
Net periodic benefit cost	$	8.6		$	12.6		$	9.4	$	9.4

No contribution to the pension trust will be necessary in or for 2011, nor will limitations on benefit payments apply.  Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts  included in the current rates for SCE&G’s retail electric and gas distribution regulated operations.  In connection with the SCPSC’s July 2010 retail electric rate order and November 2010 natural gas RSA order, SCE&G began deferring all pension expense or income related to retail electric and gas operations as a regulatory asset or liability, as applicable.  Costs totaling $2.3 million and $4.6 million were deferred for the three and six months ended June 30, 2011, respectively.  Costs totaling $5.4 million and $10.7 million were deferred for the corresponding periods in 2010.

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DERIVATIVE FINANCIAL INSTRUMENTS - SCEG

6 Months Ended

Jun. 30, 2011

DERIVATIVE FINANCIAL INSTRUMENTS

6. 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.

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.  Cash settlement of commodity derivatives are classified as an operating activity in the condensed consolidated statements of cash flows.

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 recorded 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.  Gains on certain swaps which were terminated prior to maturity of the underlying debt instruments 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 portion of settlement payments made or received upon termination are amortized to interest expense over the term of the underlying debt.  These settlements are classified as an investing activity in the condensed consolidated statements of cash flows.

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, 2011
Cash flow	-	5,524,000	18,671,098	24,195,098
Not designated (a)	10,014,000	-	23,382,436	33,396,436
Total (a)	10,014,000	5,524,000	42,053,534	57,591,534
As of December 31, 2010
Cash flow	-	5,715,000	17,190,351	22,905,351
Not designated (b)	10,677,000	-	20,588,581	31,265,581
Total (b)	10,677,000	5,715,000	37,778,932	54,170,932

(a)  Includes an aggregate  8,019,000 DT related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 6,485,536 DT related to basis swap contracts in Energy Marketing.

At June 30, 2011 and December 31, 2010, the Company was party to interest rate swaps designated as fair value hedges with an aggregate notional amount of $253.2 million and $556.4 million, respectively, and was party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $572.6 million and $1.1 billion, 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, 2011
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other		$		2	Other current liabilities		$		14
	Other deferred debits		4			Other deferred credits		30
Commodity contracts	Other current liabilities		1			Other current liabilities		3
						Other deferred credits		2
Total			$		7			$		49
Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other		$		3
Energy management contracts	Prepayments and other				4	Other deferred debits		$		1
	Other deferred debits		3			Other current liabilities		4
	Other deferred credits		1			Other deferred credits		3
Total			$		11			$		8
As of December 31, 2010
Derivatives designated as hedging instruments
Interest rate contracts	Other current assets	$		1			Other current liabilities	$	57
	Other deferred debits			7			Other deferred credits		25
Commodity contracts	Other current liabilities	1					Other current liabilities	5
							Other deferred credits	2
Total		$		9				$	89
Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other	$			3
Energy management contracts	Prepayments and other	7					Prepayments and other	$			1
	Other deferred debits	2					Other current liabilities	6
							Other deferred credits	2
Total		$			12			$			9

(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 deferred gains on previously terminated swaps as discussed above, resulted in reductions to interest expense of $1.5 million and $4.0 million for the three and six months ended June 30, 2011, respectively,  and $2.0 million and $5.2 million for the three and six months ended June 30, 2010, 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, 2011
Interest rate contracts	$	(15	)	Interest expense	$	-
Six Months Ended June 30,  2011
Interest rate contracts	$	(9	)	Interest expense	$	(1	)
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)
		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, 2011
Interest rate contracts	$	(14	)	Interest expense	$	(1	)
Commodity contracts		(1	)	Gas Purchased for resale		-
Total	$	(15	)		$	(1	)
Six Months Ended June 30, 2011
Interest rate contracts	$	(11	)	Interest expense	$	(2	)
Commodity contracts		(2	)	Gas Purchased for resale		(4	)
Total	$	(13	)		$	(6	)
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)

As of June 30, 2011, 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 $1.4 million as an increase to gas cost and approximately $4.5 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of June 30, 2011, 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	2011			2010
Second Quarter
Commodity contracts	Gas purchased for resale	$	-		$	(1	)
Year to Date
Commodity contracts	Gas purchased for resale	$	(1	)	$	(2	)

Hedge Ineffectiveness

Other gains (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three and six months ended June 30, 2011 and 2010.

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, 2011 and December 31, 2010, the Company has posted $17.0 million and $20.0 million, respectively, 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, 2011 and December 31, 2010, the Company would be required to post an additional $36.9 million and $74.0 million, respectively, 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, 2011 and December 31, 2010 are $53.9 million and $94.0 million, respectively.

SOUTH CAROLINA ELECTRIC AND GAS COMPANY

DERIVATIVE FINANCIAL INSTRUMENTS

6. 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 the 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.  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.  Cash settlement of commodity derivatives are classified as an operating activity in the condensed consolidated statements of cash flows.

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 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 portion of settlement payments made or received upon termination are amortized to interest expense over the term of the underlying debt.  These settlements are classified as an investing activity in the condensed consolidated statements of cash flows.

Quantitative Disclosures Related to Derivatives

SCE&G was party to natural gas derivative contracts for 2,420,000 DT at June 30, 2011 and 2,460,000 DT at December 31, 2010.  Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $221.4 million at June 30, 2011 and $421.4 million at December 31, 2010.

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 (a)	Value		Location (a)	Value
As of June 30, 2011
Derivatives designated as hedging instruments
Interest rate contracts	Other deferred debits	$	3	Other deferred credits	$	12
Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other	$	1
As of December 31, 2010
Derivatives designated as hedging instruments
Interest rate contracts	Other deferred debits	$	4	Other current liabilities	$	34
				Other deferred credits	1
Total		$	4		$	35
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 with the same counterparty are reported as either a net asset or liability.

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

				Gain (Loss) Reclassified from
Derivatives in Cash Flow	Gain (Loss) Deferred			Deferred Accounts into Income
Hedging Relationships	in Regulatory Accounts			(Effective Portion)
Millions of dollars	(Effective Portion)			Location	Amount
Three Months Ended June 30, 2011
Interest rate contracts	$	(15	)	Interest expense	$	-
Six Months Ended June 30, 2011
Interest rate contracts	$	(9	)	Interest expense	$	(1	)
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	)

	Gain (Loss) Recognized in Income
Derivatives Not Designated as
Hedging Instruments
Millions of dollars	Location	2011			2010
Second Quarter
Commodity contracts	Gas purchased for resale	$	-		$	(1	)
Year to Date
Commodity contracts	Gas purchased for resale	$	(1	)	$	(2	)

Hedge Ineffectiveness

Other gains (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three and six months ended June 30, 2011 and 2010.

Credit Risk Considerations

Certain of Consolidated SCE&G’s derivative instruments contain contingent provisions that require collateral to be provided upon the occurrence of specific events, primarily credit downgrades.  As of June 30, 2011 and December 31, 2010, Consolidated SCE&G has posted no collateral, respectively, 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, 2011 and December 31, 2010, Consolidated SCE&G would be required to post $11.6 million and $34.9 million, respectively, 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, 2011 and December 31, 2010 is $11.6 million and $34.9 million, respectively.

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AFFILIATED TRANSACTIONS - SCEG (SOUTH CAROLINA ELECTRIC AND GAS COMPANY)

6 Months Ended

Jun. 30, 2011

SOUTH CAROLINA ELECTRIC AND GAS COMPANY

AFFILIATED TRANSACTIONS

10. 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 $2.1 million payable to CGT for transportation services at June 30, 2011 and December 31, 2010, 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 $96.7 million and $89.0 million for the six months ended June 30, 2011 and 2010, respectively.  SCE&G’s payables to SEMI for such purposes were $17.4 million and $16.1 million as of June 30, 2011 and December 31, 2010, 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 accounts for these investments using the equity method.  SCE&G’s receivables from these affiliates were $16.9 million at June 30, 2011 and insignificant at December 31, 2010.  SCE&G’s payables to these affiliates were $17.0 million at June 30, 2011 and insignificant at December 31, 2010.  SCE&G’s total purchases were $53.3 million and $40.8 million for the six months ended June 30, 2011 and 2010, respectively.  SCE&G’s total sales were $53.1 million and $40.4 million for the six months ended June 30, 2011 and 2010, respectively.

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 expense from money pool transactions was not significant for the six months ended June 30, 2011 or 2010.  At June 30, 2011 and December 31, 2010, Consolidated SCE&G owed an affiliate $62.5 million and $71.0 million, respectively.

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DERIVATIVE FINANCIAL INSTRUMENTS (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2011 Dekatherm	Dec. 31, 2010 Dekatherm
Natural Gas Derivative Contracts and Interest Rate Swaps Outstanding
Commodity and other energy management contracts designated as cash flow hedges (in DT)	24,195,098	22,905,351
Commodity and other energy management contracts not designated as hedges (in DT)	33,396,436	31,265,581
Commodity and other energy management contracts (in DT)	57,591,534	54,170,932
Aggregate notional amount of interest rate swaps designated as fair value hedge (in dollars)	$ 253.2	$ 556.4
Aggregate notional amount of interest rate swaps designated as cash flow hedge (in dollars)	$ 572.6	$ 1,100.0
Gas Distribution
Natural Gas Derivative Contracts and Interest Rate Swaps Outstanding
Commodity and other energy management contracts not designated as hedges (in DT)	10,014,000	10,677,000
Commodity and other energy management contracts (in DT)	10,014,000	10,677,000
Retail Gas Marketing
Natural Gas Derivative Contracts and Interest Rate Swaps Outstanding
Commodity and other energy management contracts designated as cash flow hedges (in DT)	5,524,000	5,715,000
Commodity and other energy management contracts (in DT)	5,524,000	5,715,000
Energy Marketing
Natural Gas Derivative Contracts and Interest Rate Swaps Outstanding
Commodity and other energy management contracts designated as cash flow hedges (in DT)	18,671,098	17,190,351
Commodity and other energy management contracts not designated as hedges (in DT)	23,382,436	20,588,581
Commodity and other energy management contracts (in DT)	42,053,534	37,778,932
Basis swap contracts in Energy Marketing (in DT)	8,019,000	6,485,536

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

6 Months Ended

Jun. 30, 2011

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Reconciliation of the weighted average number of common shares

	Quarterly		Year to Date
In Millions	2011	2010	2011	2010
Weighted Average Shares Outstanding  - Basic	128.5	125.2	128.2	124.5
Net effect of dilutive stock-based compensation plans and equity forward contracts	1.2	0.2	1.2	0.1
Weighted Average Shares - Diluted	129.7	125.4	129.4	124.6

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CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
CONDENSED CONSOLIDATED BALANCE SHEETS
Goodwill, accumulated amortization and writedown	$ 276	$ 276
Nonutility property, accumulated depreciation	127	118
Receivables, allowance for uncollectible accounts	$ 6	$ 9

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DERIVATIVE FINANCIAL INSTRUMENTS (Details 3) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
DERIVATIVE FINANCIAL INSTRUMENTS
Reduction to interest expense for combined amount of gains on fair value hedges, losses on hedged fixed rate debt, and amortization of deferred gain on previously terminated swaps	$ 1.5	$ 2.0	$ 4.0	$ 5.2
Gain (Loss) on Derivatives
Gain (Loss) Reclassified from Accumulated OCI into Income, net of tax (Effective Portion)	(1)	(4)	(6)	(9)
Credit Risk Considerations
Collateral posted related to derivatives with contingent provisions that are in net liability position	17.0		17.0		20.0
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	36.9		36.9		74.0
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	53.9		53.9		94.0
Derivatives designated as hedging instruments | Interest rate contracts | Derivatives in Cash Flow Hedging Relationships
Gain (Loss) on Derivatives
Gain (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense	(15)	(63)	(9)	(60)
Gain (Loss) Reclassified from Deferred Accounts into Income (Effective Portion), classified in interest expense			(1)	(1)
Gain (Loss) Recognized in OCI, net of tax (Effective Portion)	(14)	(31)	(11)	(33)
Gain (Loss) Reclassified from Accumulated OCI into Income, net of tax (Effective Portion)	(1)	(1)	(2)	(2)
Expected reclassifications from accumulated other comprehensive loss to earnings arising from cash flow hedges during next 12 months			1.4
Derivatives designated as hedging instruments | Commodity contracts | Derivatives in Cash Flow Hedging Relationships
Gain (Loss) on Derivatives
Gain (Loss) Recognized in OCI, net of tax (Effective Portion)	(1)	2	(2)	(7)
Gain (Loss) Reclassified from Accumulated OCI into Income, net of tax (Effective Portion)		(3)	(4)	(7)
Expected reclassifications from accumulated other comprehensive loss to earnings arising from cash flow hedges during next 12 months			4.5
Derivatives designated as hedging instruments | Derivatives in Cash Flow Hedging Relationships
Gain (Loss) on Derivatives
Gain (Loss) Recognized in OCI, net of tax (Effective Portion)	(15)	(29)	(13)	(40)
Gain (Loss) Reclassified from Accumulated OCI into Income, net of tax (Effective Portion)	(1)	(4)	(6)	(9)
Derivatives not designated as hedging instruments | Commodity contracts
Gain (Loss) on Derivatives
Gain (Loss) Recognized in Income, classified in gas purchased for resale		$ (1)	$ (1)	$ (2)

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - SCEG (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Accumulated other comprehensive loss	$ 53.2	$ 46.6
SOUTH CAROLINA ELECTRIC AND GAS COMPANY
Accumulated other comprehensive loss	$ 2.6	$ 2.7

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EMPLOYEE BENEFIT PLANS - SCEG

6 Months Ended

Jun. 30, 2011

EMPLOYEE BENEFIT PLANS

8. EMPLOYEE BENEFIT PLANS

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	2011			2010			2011		2010
Three months ended June 30,
Service cost	$	4.6		$	4.8		$	1.1	$	1.1
Interest cost	11.1			11.9			3.0		3.2
Expected return on assets	(16.2		)	(16.5		)	-		-
Prior service cost amortization	1.8			1.8			0.3		0.2
Transition obligation amortization	-			-			0.2		0.1
Amortization of actuarial loss	3.0			4.3			0.1		0.1
Net periodic benefit cost	$	4.3		$	6.3		$	4.7	$	4.7
Six months ended June 30,
Service cost	$	9.2		$	9.5		$	2.2	$	2.2
Interest cost	22.2			23.7			6.0		6.2
Expected return on assets	(32.4		)	(32.9		)	-		-
Prior service cost amortization	3.6			3.7			0.6		0.5
Transition obligation amortization	-			-			0.4		0.3
Amortization of actuarial loss	6.0			8.6			0.2		0.2
Net periodic benefit cost	$	8.6		$	12.6		$	9.4	$	9.4

No contribution to the pension trust will be necessary in or for 2011, nor will limitations on benefit payments apply.  Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts  included in the current rates for SCE&G’s retail electric and gas distribution regulated operations.  In connection with the SCPSC’s July 2010 retail electric rate order and November 2010 natural gas RSA order, SCE&G began deferring all pension expense or income related to retail electric and gas operations as a regulatory asset or liability, as applicable.  Costs totaling $2.3 million and $4.6 million were deferred for the three and six months ended June 30, 2011, respectively.  Costs totaling $5.4 million and $10.7 million were deferred for the corresponding periods in 2010.

SOUTH CAROLINA ELECTRIC AND GAS COMPANY

EMPLOYEE BENEFIT PLANS

8. EMPLOYEE BENEFIT PLANS

Pension and Other Postretirement Benefit Plans

Consolidated SCE&G participates in SCANA’s noncontributory defined benefit pension plan, which covers substantially all regular, full-time employees, and also participates in SCANA’s unfunded postretirement health care and life insurance programs, which provide benefits to active and retired employees.  Components of net periodic benefit cost recorded by Consolidated SCE&G were as follows:

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2011			2010			2011		2010
Three months ended June 30,
Service cost	$	3.7		$	3.5		$	0.9	$	0.9
Interest cost	9.5			10.2			2.3		2.4
Expected return on assets	(13.7		)	(14.5		)	-		-
Prior service cost amortization	1.5			1.6			0.2		0.2
Amortization of actuarial loss	2.5			4.2			0.1		-
Net periodic benefit cost	$	3.5		$	5.0		$	3.5	$	3.5
Six months ended June 30,
Service cost	$	7.4		$	7.1		$	1.8	$	1.7
Interest cost	18.9			20.4			4.7		4.8
Expected return on assets	(27.5		)	(29.0		)	-		-
Prior service cost amortization	3.0			3.3			0.4		0.4
Amortization of actuarial loss	5.1			8.4			0.1		0.1
Net periodic benefit cost	$	6.9		$	10.2		$	7.0	$	7.0

No contribution to the pension trust will be necessary in or for 2011, nor will limitations on benefit payments apply.  Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts included in current rates for SCE&G’s retail electric and gas distribution regulated operations.  In connection with the SCPSC’s July 2010 retail electric rate order and November 2010 natural gas RSA order, SCE&G began deferring all pension expense or income related to retail electric and gas operations as a regulatory asset or liability, as applicable.  Costs totaling $2.3 million and $4.6 million were deferred for the three and six months ended June 30, 2011, respectively.  Costs totaling $5.4 million and $10.7 million were deferred for the corresponding periods in 2010.

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - SCEG (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Interest charges, allowance for borrowed funds used during construction	$ 3	$ 3	$ 5	$ 5
SOUTH CAROLINA ELECTRIC AND GAS COMPANY
Interest charges, allowance for borrowed funds used during construction	$ 3	$ 3	$ 4	$ 5

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - SCEG (USD $) In Millions	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Adjustments to reconcile net income to net cash provided from operating activities:
Earnings from equity method investments, net of distribution	$ 1	$ (1)
Deferred income taxes, net	45	116
Depreciation and amortization	173	174
Amortization of nuclear fuel	14	18
Allowance for equity funds used during construction	(8)	(10)
Carrying cost recovery		(3)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	210	100
Inventories	8	30
Prepayments and other	57	(19)
Regulatory assets	(28)	(90)
Regulatory liabilities	(6)	(3)
Accounts payable	(93)	(53)
Taxes accrued	(63)	(134)
Interest accrued	2	1
Changes in other assets	(12)	(8)
Changes in other liabilities	(59)	62
Net Cash Provided From Operating Activities	425	360
Cash Flows From Investing Activities:
Utility property additions and construction expenditures	(466)	(432)
Proceeds from investments	10	8
Nonutility property additions	(11)	(15)
Purchase of investments	(13)	(22)
Settlements of interest rate contracts	(61)
Net Cash Used For Investing Activities	(541)	(461)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	796	203
Repayment of long-term debt	(623)	(67)
Dividends	(122)	(117)
Short-term borrowings, net	126	(104)
Net Cash Provided From (Used For) Financing Activities	227	21
Net Increase (Decrease) In Cash and Cash Equivalents	111	(80)
Cash and Cash Equivalents, January 1	55	162
Cash and Cash Equivalents, June 30	166	82
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $4 and $5)	134	132
Cash paid for - Income taxes		55
Noncash Investing and Financing Activities:
Accrued construction expenditures	125	95
Capital leases	2	6
SOUTH CAROLINA ELECTRIC AND GAS COMPANY
Cash Flows From Operating Activities:
Net income	132	127
Adjustments to reconcile net income to net cash provided from operating activities:
Earnings from equity method investments, net of distribution	1	1
Deferred income taxes, net	36	115
Depreciation and amortization	142	140
Amortization of nuclear fuel	14	18
Allowance for equity funds used during construction	(8)	(10)
Carrying cost recovery		(3)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	63	(11)
Inventories	3	7
Prepayments and other	43	(9)
Regulatory assets	(30)	(91)
Regulatory liabilities	(4)	(2)
Accounts payable	(46)	(19)
Taxes accrued	(59)	(127)
Interest accrued	4	(1)
Changes in other assets	(8)	(4)
Changes in other liabilities	(46)	79
Net Cash Provided From Operating Activities	237	210
Cash Flows From Investing Activities:
Utility property additions and construction expenditures	(421)	(396)
Proceeds from investments	4	8
Nonutility property additions	(4)	(1)
Investment in affiliate		41
Purchase of investments	(3)	(12)
Settlements of interest rate contracts	(31)
Net Cash Used For Investing Activities	(455)	(360)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	349	51
Repayment of long-term debt	(164)	(11)
Dividends	(104)	(97)
Contributions from parent	49	105
Short-term borrowings -affiliate, net	(9)	12
Short-term borrowings, net	94	(23)
Net Cash Provided From (Used For) Financing Activities	215	37
Net Increase (Decrease) In Cash and Cash Equivalents	(3)	(113)
Cash and Cash Equivalents, January 1	31	134
Cash and Cash Equivalents, June 30	28	21
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $4 and $5)	87	87
Cash paid for - Income taxes		31
Noncash Investing and Financing Activities:
Accrued construction expenditures	116	89
Capital leases	$ 2

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INCOME TAXES - SCEG

6 Months Ended

Jun. 30, 2011

INCOME TAXES

5. INCOME TAXES

In connection with the change in method of accounting for certain repair costs in 2010, the Company identified approximately $36 million of unrecognized tax benefit.  Because this method change is primarily a temporary difference, this additional benefit, if recognized, would not have a significant effect on the effective tax rate.  Within the next 12 months, it is reasonably possible that this unrecognized tax benefit could increase by as much as $12 million or decrease by as much as $36 million.  The events that could cause these changes are direct settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities, or the lapse of an applicable statute of limitation.  No other material changes in the status of the Company’s tax positions have occurred through June 30, 2011.

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  The Company has accrued $0.8 million of interest expense through June 2011.

SOUTH CAROLINA ELECTRIC AND GAS COMPANY

INCOME TAXES

5. INCOME TAXES

In connection with the change in method of accounting for certain repair costs in 2010, Consolidated SCE&G identified approximately $36 million of unrecognized tax benefit.  Because this method change is primarily a temporary difference, this additional benefit, if recognized, would not have a significant effect on the effective tax rate.  Within the next 12 months, it is reasonably possible that this unrecognized tax benefit could increase by as much as $12 million or decrease by as much as $36 million.  The events that could cause these changes are direct settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities, or the lapse of an applicable statute of limitation.  No other material changes in the status of Consolidated SCE&G’s tax positions have occurred through June 30, 2011.

Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  Consolidated SCE&G has accrued $0.8 million of interest expense through June 2011.

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) (Recurring basis, USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Available for sale securities	$ 3	$ 3
Commodity contracts	2	2
Liabilities
Commodity contracts	1	1
Significant Other Observable Inputs (Level 2)
Assets
Interest rate contracts	6	8
Commodity contracts	2	2
Energy management contracts	8	9
Liabilities
Interest rate contracts	44	82
Commodity contracts	4	6
Energy management contracts	$ 8	$ 11