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 March 31, 2013

OR

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

For the Transition Period from to

Commission	Registrant, State of Incorporation,	I.R.S. Employer
File Number	Address and Telephone Number	Identification No.
1-8809	SCANA Corporation	57-0784499
	(a South Carolina corporation)
	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 ¨  South Carolina Electric & Gas Company Yes x No ¨

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 ¨  South Carolina Electric & Gas Company Yes x No ¨

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

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

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

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

	Description of	Shares Outstanding
Registrant	Common Stock	at April 30, 2013
SCANA Corporation	Without Par Value	139,498,499
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).

MARCH 31, 2013

			Page
Cautionary Statement Regarding Forward-Looking Information			3
Definitions			4
PART I. FINANCIAL INFORMATION
SCANA Corporation Financial Section			6
	Item 1.	Financial Statements	7
		Condensed Consolidated Balance Sheets	7
		Condensed Consolidated Statements of Income	9
		Condensed Consolidated Statements of Comprehensive Income	10
		Condensed Consolidated Statements of Cash Flows	11
		Notes to Condensed Consolidated Financial Statements	12
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
	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 Comprehensive Income	39
		Condensed Consolidated Statements of Cash Flows	40
		Notes to Condensed Consolidated Financial Statements	41
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	52
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	55
	Item 4.	Controls and Procedures	55
PART II. OTHER INFORMATION			56
	Item 6.	Exhibits	56
Signatures			57
Exhibit Index			58

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, 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 markets;

(6) the impact of conservation and demand side management efforts and/or technological advances on customer usage;

(7) growth opportunities for SCANA’s regulated and diversified subsidiaries;

(8) the results of short- and long-term financing efforts, including prospects for obtaining access to capital markets and other sources of liquidity;

(9) changes in SCANA’s or its subsidiaries’ accounting rules and accounting policies;

(10) 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;

(11) payment and performance by counterparties and customers as contracted and when due;

(12) the results of efforts to license, site, construct and finance facilities for electric generation and transmission;

(13) maintaining creditworthy joint owners for SCE&G’s new nuclear generation project;

(14) the ability of suppliers, both domestic and international, to timely provide the labor, components, parts, tools, equipment and other supplies needed, at agreed upon prices, for our construction program, operations and maintenance;

(15) the results of efforts to ensure the physical and cyber security of key assets and processes;

(16) 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;

(17) the availability of skilled and experienced human resources to properly manage, operate, and grow the Company’s businesses;

(18) labor disputes;

(19) performance of SCANA’s pension plan assets;

(20) changes in taxes;

(21) inflation or deflation;

(22) compliance with regulations;

(23) natural disasters and man-made mishaps that directly affect our operations or the regulations governing them; and

(24) 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

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
ANI	American Nuclear Insurers
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement Obligation
BACT	Best Available Control Technology
BLRA	Base Load Review Act
CAA	Clean Air Act, as amended
CAIR	Clean Air Interstate 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
Consortium	A consortium consisting of Westinghouse and Stone and Webster, Inc., a subsidiary of The Shaw Group, Inc.
CSAPR	Cross-State Air Pollution Rule
CUT	Customer Usage Tracker
DHEC	South Carolina Department of Health and Environmental Control
DOJ	United States Department of Justice
DSM Programs	Demand reduction and energy efficiency programs
EIZ Credits	South Carolina Capital Investment Tax Credits (formerly known as Economic Impact Zone Income Tax Credits)
Energy Marketing	The divisions of SEMI, excluding SCANA Energy
EPA	United States Environmental Protection Agency
EPC Contract	Engineering, Procurement and Construction Agreement dated May 23, 2008
eWNA	Pilot Electric WNA
FERC	United States Federal Energy Regulatory Commission
Fuel Company	South Carolina Fuel Company, Inc.
GENCO	South Carolina Generating Company, Inc.
GHG	Greenhouse Gas
GWh	Gigawatt hour
IRP	Integrated Resource Plan
JEDA	South Carolina Jobs-Economic Development Authority
LOC	Lines of Credit
MGP	Manufactured Gas Plant
MMBTU	Million British Thermal Units
MW	Megawatt
NASDAQ	The NASDAQ Stock Market, Inc.
NCUC	North Carolina Utilities Commission
NEIL	Nuclear Electric Insurance Limited
New Units	Nuclear Units 2 and 3 under construction at Summer Station
NRC	United States Nuclear Regulatory Commission
NSPS	New Source Performance Standards
NSR	New Source Review
NYMEX	New York Mercantile Exchange
OCI	Other Comprehensive Income

4

ORS	South Carolina Office of Regulatory Staff
PGA	Purchased Gas Adjustment
Price-Anderson	Price-Anderson Indemnification Act
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
SEC	United States Securities and Exchange Commission
SEMI	SCANA Energy Marketing, Inc.
Summer Station	V. C. Summer Nuclear Station
VIE	Variable Interest Entity
Westinghouse	Westinghouse Electric Company LLC
WNA	Weather Normalization Adjustment

5

SCANA CORPORATION

FINANCIAL SECTION

6

PART I.  FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

SCANA CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited) 

Millions of dollars	March 31, 2013			December 31, 2012
Assets
Utility Plant In Service	$	11,937		$	11,865
Accumulated Depreciation and Amortization	(3,867		)	(3,811		)
Construction Work in Progress	2,250			2,084
Plant to be Retired, Net	359			362
Nuclear Fuel, Net of Accumulated Amortization	251			166
Goodwill, net of writedown of $230	230			230
Utility Plant, Net	11,160			10,896
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $142 and $139	306			306
Assets held in trust, net-nuclear decommissioning	97			94
Other investments	89			87
Nonutility Property and Investments, Net	492			487
Current Assets:
Cash and cash equivalents	43			72
Receivables, net of allowance for uncollectible accounts of $7 and $7	775			780
Inventories (at average cost):
Fuel and gas supply	250			304
Materials and supplies	140			136
Emission allowances	1			1
Prepayments and other	185			223
Deferred income taxes	10			11
Total Current Assets	1,404			1,527
Deferred Debits and Other Assets:
Regulatory assets	1,451			1,464
Other	250			242
Total Deferred Debits and Other Assets	1,701			1,706
Total	$	14,757		$	14,616

7

Millions of dollars	March 31, 2013		December 31, 2012
Capitalization and Liabilities
Common Equity	$	4,463	$	4,154
Long-Term Debt, net	5,039		4,949
Total Capitalization	9,502		9,103
Current Liabilities:
Short-term borrowings	530		623
Current portion of long-term debt	173		172
Accounts payable	360		428
Customer deposits and customer prepayments	82		86
Taxes accrued	63		164
Interest accrued	76		82
Dividends declared	70		66
Derivative financial instruments	66		80
Other	76		110
Total Current Liabilities	1,496		1,811
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,673		1,653
Deferred investment tax credits	35		36
Asset retirement obligations	567		561
Postretirement benefits	389		387
Regulatory liabilities	917		882
Other	178		183
Total Deferred Credits and Other Liabilities	3,759		3,702
Commitments and Contingencies (Note 9)	—		—
Total	$	14,757	$	14,616

See Notes to Condensed Consolidated Financial Statements.

8

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended
	March 31,
Millions of dollars, except per share amounts	2013			2012
Operating Revenues:
Electric	$	583		$	545
Gas - regulated	382			277
Gas - nonregulated	346			285
Total Operating Revenues	1,311			1,107
Operating Expenses:
Fuel used in electric generation	186			181
Purchased power	7			6
Gas purchased for resale	501			366
Other operation and maintenance	176			175
Depreciation and amortization	93			89
Other taxes	55			52
Total Operating Expenses	1,018			869
Operating Income	293			238
Other Income (Expense):
Other income	13			14
Other expense	(12		)	(10		)
Interest charges, net of allowance for borrowed funds used during construction of $2 and $2	(75		)	(72		)
Allowance for equity funds used during construction	4			3
Total Other Expense	(70		)	(65		)
Income Before Income Tax Expense	223			173
Income Tax Expense	72			52
Net Income	$	151		$	121
Per Common Share Data
Basic Earnings Per Share of Common Stock	$	1.13		$	0.93
Diluted Earnings Per Share of Common Stock	$	1.11		$	0.91
Weighted Average Common Shares Outstanding (millions)
Basic	134.4			130.3
Diluted	136.1			132.2
Dividends Declared Per Share of Common Stock	$	.5075		$	.495

See Notes to Condensed Consolidated Financial Statements.

9

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited) 

	Three Months Ended March 31,
Millions of dollars	2013		2012
Net Income	$	151	$	121
Other Comprehensive Income (Loss), net of tax:
Unrealized gains (losses) on cash flow hedging activities arising during period, net of tax of $2 and $(2)	3		(4		)
Losses on cash flow hedging activities reclassified to net income, net of tax of $2 and $6	4		10
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax of $- and $-	—		—
Other Comprehensive Income	7		6
Total Comprehensive Income	$	158	$	127

Accumulated other comprehensive loss totaled $78.8 million as of March 31, 2013 and $85.6 million as of December 31, 2012.

See Notes to Condensed Consolidated Financial Statements.

10

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited) 

	Three Months Ended March 31,
Millions of dollars	2013			2012
Cash Flows From Operating Activities:
Net income	$	151		$	121
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred income taxes, net	17			50
Depreciation and amortization	97			92
Amortization of nuclear fuel	13			13
Allowance for equity funds used during construction	(4		)	(3		)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	(22		)	65
Inventories	37			(11		)
Prepayments and other	21			68
Regulatory liabilities	26			1
Accounts payable	5			(18		)
Taxes accrued	(101		)	(101		)
Interest accrued	(6		)	(1		)
Regulatory assets	12			41
Changes in other assets	(16		)	(43		)
Changes in other liabilities	(37		)	(89		)
Net Cash Provided From Operating Activities	193			185
Cash Flows From Investing Activities:
Property additions and construction expenditures	(291		)	(321		)
Proceeds from investments (including derivative collateral posted)	100			151
Purchase of investments (including derivative collateral posted)	(84		)	(109		)
Proceeds from interest rate contract settlement	—			13
Payments upon interest rate contract settlement	—			(51		)
Net Cash Used For Investing Activities	(275		)	(317		)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock	221			26
Proceeds from issuance of long-term debt	57			494
Repayment of long-term debt	(66		)	(259		)
Dividends	(66		)	(63		)
Short-term borrowings, net	(93		)	(68		)
Net Cash Provided From Financing Activities	53			130
Net Decrease In Cash and Cash Equivalents	(29		)	(2		)
Cash and Cash Equivalents, January 1	72			29
Cash and Cash Equivalents, March 31	$	43		$	27
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $2 and $2)	$	77		$	74
– Income taxes	1			—
Noncash Investing and Financing Activities:
Accrued construction expenditures	88			108
Capital leases	3			—
Nuclear fuel purchase	97			—

 See Notes to Condensed Consolidated Financial Statements.

11

SCANA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the Three Months Ended March 31, 2013 and 2012

(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, 2012. 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.

Plant to be Retired

SCE&G has six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units have an aggregate generating capacity (summer 2012) of 730 MW. One unit (90 MW) has been retired and its value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units totaled $359 million at March 31, 2013 and is included in Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.

Earnings Per Share

The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period.  The Company computes diluted earnings per share using this same formula after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method.  The Company has issued no securities that would have an antidilutive effect on earnings per share.

Reconciliations of the weighted average number of common shares for basic and diluted earnings per share computation purposes are as follows:

Millions	2013	2012
Weighted Average Shares Outstanding - Basic	134.4	130.3
Net effect of dilutive equity forward shares	1.7	1.9
Weighted Average Shares - Diluted	136.1	132.2

Asset Management and Supply Service Agreements

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities.  Such counterparties held 18% and 44% of PSNC Energy’s natural gas inventory at March 31, 2013

and December 31, 2012, respectively, with a carrying value of $3.4 million and $19.6 million, respectively, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees. The agreements expire at various times through March 31, 2015.

12

2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G's retail electric rates include 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. In April 2012, the SCPSC approved SCE&G's request to decrease the total fuel cost component of its retail electric rates, and approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to recover an amount equal to its actual under-collected balance of base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a 12-month period beginning with the first billing cycle of May 2012.

In the December 2012 rate order, the SCPSC authorized SCE&G to reduce the base fuel cost component of its retail electric rates and in doing so, stated that SCE&G may not adjust its base fuel component prior to April 1, 2014, except where necessary due to extraordinary unforeseen economic or financial conditions.  In February 2013, in connection with its annual review of base rates for fuel costs, SCE&G requested authorization to reduce its environmental fuel cost component effective with the first billing cycle of May 2013.  Consistent with the December 2012 rate order, however, SCE&G did not request any adjustment to its base fuel cost component.  On March 14, 2013 SCE&G, ORS and the SCEUC entered into a settlement agreement accepting the proposed lower environmental fuel cost component effective the first billing cycle of May 2013.  By not adjusting SCE&G's base fuel component, the settlement also provided for carrying costs on a portion of the undercollected balance of fuel costs.  The SCPSC approved this settlement agreement on April 10, 2013.

On December 19, 2012, the SCPSC approved a 4.23% overall increase in SCE&G's retail electric base rates, effective January 1, 2013, and authorized an allowed return on common equity of 10.25%. The SCPSC also approved a mid-period reduction to the cost of fuel component in rates, a reduction in the DSM Programs component rider to retail rates, and the recovery of and a return on the net carrying value of certain retired generating plant assets described below. By order dated February 7, 2013, the SCPSC denied the SCEUC's petition for rehearing of this order.

The eWNA is designed to reduce volatility of costs charged to residential and commercial customers due to abnormal weather and is based on a 15 year historical average of temperatures. In connection with the December 2012 rate order, SCE&G agreed to perform a study of alternative structures for eWNA by June 30, 2013, which may be used to modify or terminate eWNA in the future.

In February 2013, SCE&G filed an IRP with the SCPSC. The IRP evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. The IRP identified a total of six coal-fired units that SCE&G intends to retire by 2018, subject to future developments in environmental regulations, among other matters. The net carrying value of a unit that has been retired is recorded in regulatory assets as unrecovered plant and is being amortized over its original remaining useful life as further described below. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.

SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and lost net margin revenue associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G submits annual filings in January to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC has approved the following rate changes pursuant to annual DSM Programs filings, which changes went into effect as indicated below:

Year	Effective	Amount
2012	First billing cycle of May	$19.6 million
2011	First billing cycle of June	$7.0 million

In January 2013, SCE&G filed its annual update on DSM Programs and a petition for an update to the rate rider requesting an increase of approximately $27.2 million. On April 1, 2013, ORS filed a report of its review of SCE&G's DSM Programs petition with the SCPSC. ORS proposed that SCE&G recover the net lost revenue component of the rider of $20.6

13

million over a 24-month period effective for bills rendered on and after the first billing cycle in May 2013. ORS also recommended that SCE&G defer a portion of net lost revenue component in a regulatory asset and recover those amounts over a 12-month period effective for bills rendered on and after the first billing cycle in May 2014. SCE&G agreed with ORS's recommendations. In April 2013, the SCPSC approved SCE&G's request to update its rider as modified by the agreement between ORS and SCE&G.

Electric – BLRA

In November 2012, the SCPSC approved an updated construction schedule and additional updated capital costs of $278 million (SCE&G's portion in 2007 dollars). The November 2012 order approved additional identifiable capital costs of approximately $1 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications; approximately $8 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure; and approximately $132 million (SCE&G's portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. In addition, the order approved revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims for costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals.

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 11.0%. The SCPSC has approved the following rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated:

Year	Action			Amount
2012	2.3	%	Increase	$52.1 million
2011	2.4	%	Increase	$52.8 million

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. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the years indicated:

Year	Action			Amount
2012	2.1	%	Increase	$7.5 million
2011	2.1	%	Increase	$8.6 million

SCE&G's natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. SCE&G's gas rates are calculated using a methodology which may adjust 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 held in November 2012 before the SCPSC. The SCPSC issued an order in December 2012 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2011 through July 31, 2012, were reasonable and prudent.

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.

14

PSNC Energy’s rates are established using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collection of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In 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 2012, in connection with PSNC Energy's 2012 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, 2012.

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 regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.

Millions of dollars	March 31, 2013		December 31, 2012
Regulatory Assets:
Accumulated deferred income taxes	$	254	$	254
Under-collections - electric fuel adjustment clause	75		66
Environmental remediation costs	43		44
AROs and related funding	324		319
Franchise agreements	34		36
Deferred employee benefit plan costs	452		460
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	141		151
Deferred pollution control costs	38		38
Unrecovered plant	20		20
Other	70		70
Total Regulatory Assets	$	1,451	$	1,464

Regulatory Liabilities:
Accumulated deferred income taxes	$	20	$	21
Asset removal costs	701		692
Storm damage reserve	27		27
Monetization of bankruptcy claim	31		32
Deferred gains on interest rate derivatives	137		110
Planned major maintenance	1		—
Total Regulatory Liabilities	$	917	$	882

Accumulated deferred income tax liabilities that arose from utility operations that have not been included in customer rates are recorded as a regulatory asset.  Substantially all of these regulatory assets relate to depreciation and 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 not expected to be recovered in retail electric rates within 12 months. 

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 28 years.

15

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. In connection with the December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are to be recovered through utility rates over approximately 30 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 12 years.

Planned major maintenance related to certain fossil fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders.  SCE&G collects $18.4 million annually for fossil fueled turbine/generation equipment maintenance.  Through December 31, 2012, nuclear refueling charges were accrued during each 18-month refueling outage cycle as a component of cost of service. In connection with the December 2012 rate order, effective January 1, 2013, SCE&G began to collect and accrue $17.2 million annually for nuclear-related refueling charges.

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.

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at Wateree and Williams Stations pursuant to specific regulatory orders.  Such costs will be recovered through utility rates over periods up to 30 years. 

Unrecovered plant represents the net book value of a coal-fired generating unit retired from service prior to being fully depreciated. Pursuant to the December 2012 rate order, SCE&G is amortizing these amounts over the unit's original remaining useful life of approximately 14 years. Unamortized amounts are included in rate base.

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. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely.

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

The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been approved for recovery by the SCPSC, the NCUC or by the FERC. In recording such 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. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. 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 effect on the Company's results of operations, liquidity or financial position in the period the write-off would be recorded.

16

3.  COMMON EQUITY

Changes in common equity during the three months ended March 31, 2013 and 2012 were as follows:

Millions of dollars	2013			2012
Balance at January 1,	$	4,154		$	3,889
Common stock issued	221			26
Dividends declared	(70		)	(65		)
Comprehensive income	158			127
Balance as of March 31,	$	4,463		$	3,977

SCANA had 200 million shares of common stock authorized as of March 31, 2013 and December 31, 2012, of which 139.2 million and 132.0 million were issued and outstanding at March 31, 2013 and December 31, 2012, respectively.

On March 5, 2013, SCANA settled all forward sales contracts related to its common stock through the issuance of approximately 6.6 million common shares, resulting in net proceeds of approximately $196.2 million.

Reclassifications of gains (losses) from AOCI into earnings were as follows:

	Three Months Ended March 31,						Income Statement
Millions of dollars	2013			2012			Line Item Affected
Interest rate contracts	$	(2	)	$	(2	)	Increase in interest expense
Commodity contracts	(2		)	(8		)	Increase in gas purchased for resale
Amortization of deferred employee benefit plan costs	—			—
Total reclassifications	$	(4	)	$	(10	)

Reclassifications of the amortization of deferred employee benefit costs were not significant for any period presented.

4. LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In January 2013, JEDA issued at a premium, for the benefit of SCE&G, $39.5 million of 4.0% tax-exempt industrial revenue bonds due February 1, 2028, and $14.7 million of 3.63% tax-exempt industrial revenue bonds due February 1, 2033. Proceeds from these sales were loaned by JEDA to SCE&G and, together with other available funds, were used to redeem prior to maturity $56.9 million of 5.2% industrial revenue bonds due November 1, 2027.

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.

17

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
Millions of dollars	March 31, 2013			December 31, 2012			March 31, 2013			December 31, 2012			March 31, 2013		December 31, 2012
Lines of credit:
Total committed long-term	$	300		$	300		$	1,400		$	1,400		$	100	$	100
LOC advances	—			—			—			—			—		—
Weighted average interest rate	—			—			—			—			—		—
Outstanding commercial paper (270 or fewer days)	$	122		$	142		$	408		$	449		—		$	32
Weighted average interest rate	0.48		%	0.58		%	0.33		%	0.42		%	—		0.44		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—		—
Available	$	175		$	155		$	992		$	951		$	100	$	68

SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million, $1.2 billion (of which $500 million relates to Fuel Company) and $100 million, respectively, which expire in October  2017. In addition, SCE&G is party to a new three-year credit agreement in the amount of $200 million which expires in October 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, certain fossil fuels, 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 10.7% of the aggregate $1.8 billion credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. Credit Suisse AG, Cayman Island Branch and UBS Loan Finance LLC each provide 8.9%, and Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 6.3%.  Two other banks provide the remaining support. The Company pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented.

The Company is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company.  The letters of credit expire, subject to renewal, in the fourth quarter of 2014.

5. INCOME TAXES

 In connection with a prior change in method of tax accounting for certain repair costs, the Company had previously recorded an unrecognized tax benefit of $38 million. Under newadministrative guidance from the Internal Revenue Service, the Company recognized all of the previously unrecognized tax benefit in the first quarter of 2012. Since this change was primarily a temporary difference, the recognition of this benefit did not have a significant effect on the Company's effective tax rate. No other material changes in the status of the Company's tax positions have occurred through March 31, 2013.

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. In connection with the resolution of the uncertainty and recognition of tax benefits described above, during the quarter ended March 31, 2012, the Company reversed $2 million of interest expense which had been accrued during 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. 

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

18

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 Audit Committee of the Board of Directors with regard to the management of risk and brings to the Audit Committee's attention significant 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 companies and financial institutions.  Cash settlements of commodity derivatives are classified as operating activities in the condensed consolidated statements of cash flows.

PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options.  PSNC Energy’s tariffs also include a provision for the recovery of actual gas costs incurred, including any costs of hedging.  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 OCI.  When the hedged transactions affect earnings, the previously recorded gains and losses are reclassified from AOCI 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. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes.

Interest Rate Swaps

The Company may use interest rate swaps to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances.  These swaps may be designated as either fair value hedges or cash flow hedges.

The Company synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges. Periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

In anticipation of the issuance of debt, the Company may use treasury rate lock or forward starting swap agreements that 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 OCI.  Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions are recognized in income.  Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes.

19

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 MMBTU)
Hedge designation	Gas Distribution	Retail Gas Marketing	Energy Marketing	Total
As of March 31, 2013
Cash flow	—	4,074,000	14,344,000	18,418,000
Not designated (a)	4,850,000	—	14,085,848	18,935,848
Total (a)	4,850,000	4,074,000	28,429,848	37,353,848
As of December 31, 2012
Cash flow	—	6,490,000	18,937,000	25,427,000
Not designated (b)	5,170,000	—	17,703,275	22,873,275
Total (b)	5,170,000	6,490,000	36,640,275	48,300,275

(a)  Includes an aggregate 1,850,000 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 3,500,000 MMBTU related to basis swap contracts in Energy Marketing.

The Company was not party to any interest rate swap designated as a fair value hedge during any period presented. The Company was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $1.1 billion at each of March 31, 2013 and December 31, 2012.

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

	Fair Values of Derivative Instruments
	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
Millions of dollars	Location	Value		Location	Value
As of March 31, 2013
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	58	Other current liabilities	$	62
	Other deferred debits and other assets	42		Other deferred credits and other liabilities	33
Commodity	Prepayments and other	2		Prepayments and other	1
Total		$	102		$	96
Derivatives not designated as hedging instruments
Commodity	Prepayments and other	$	2
Energy management	Prepayments and other	5		Other current liabilities	$	5
	Other deferred debits and other assets	5		Other deferred credits and other liabilities	5
Total		$	12		$	10

20

As of December 31, 2012
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	42	Other current liabilities	$	70
	Other deferred debits and other assets	31		Other deferred credits and other liabilities	36
Commodity	Prepayments and other	1		Other current liabilities	4
Total		$	74		$	110
Derivatives not designated as hedging instruments
Commodity	Prepayments and other	$	1
Energy management	Prepayments and other	7		Prepayments and other	$	1
	Other deferred debits and other assets	6		Other current liabilities	6
				Other deferred debits and other assets	6
Total		$	14		$	13

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

Fair Value Hedges

With regard to the Company's interest rate swaps designated as fair value hedges, any gains or losses related to the swaps or the fixed rate debt are recognized in current earnings and included in interest expense.  Such gains and losses, combined with the amortization of deferred gains on previously terminated swaps, were not significant during any period presented.

Cash Flow Hedges

Derivatives in Cash Flow Hedging Relationships

					Loss Reclassified from
	Gain (Loss) Deferred				Deferred Accounts into Income
	in Regulatory Accounts				(Effective Portion)
Millions of dollars	(Effective Portion)				Location	Amount
	2013		2012			2013			2012
Three Months Ended March 31,
Interest rate	$	35	$	30	Interest expense	$	(1	)	$	(1	)

	Gain (Loss)					Loss Reclassified from
	Recognized in OCI,					AOCI into Income,
	net of tax					net of tax (Effective Portion)
	(Effective Portion)					Location	Amount
	2013		2012				2013			2012
Three Months Ended March 31,
Interest rate	$	1	—			Interest expense	$	(2	)	$	(2	)
Commodity	2		$	(4	)	Gas purchased for resale	(2		)	(8		)
Total	$	3	$	(4	)		$	(4	)	$	(10	)

As of March 31, 2013, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive income (loss) to earnings arising from cash flow hedges will include approximately $0.7 million as a decrease to gas cost and approximately $6.0 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of March 31, 2013, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2015.

21

Derivatives not designated as Hedging Instruments	Loss Recognized in Income
Millions of dollars	Location	2013		2012
Three Months Ended March 31,
Commodity	Gas purchased for resale	$	—	$	(1	)

Hedge Ineffectiveness

Other losses recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three months ended March 31, 2013 and 2012, respectively.

Credit Risk Considerations

The Company limits credit risk in its commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. In this regard, the Company uses credit ratings provided by credit rating agencies and current market-based qualitative and quantitative data, as well as financial statements, to assess the financial health of counterparties on an ongoing basis. The Company uses standardized master agreements which may include collateral requirements. These master agreements permit the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements (if any) require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with the Company's credit policies and due diligence. In addition, collateral agreements (if any) allow for the termination and liquidation of all positions in the event of a failure or inability to post collateral.

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 March 31, 2013 and December 31, 2012, the Company has posted $60.6 million and $78.3 million, respectively, of collateral related to derivatives with contingent provisions that were in a net liability position.  Collateral related to the positions expected to close in the next 12 months is recorded in Prepayments and other on the consolidated balance sheets. Collateral related to the noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of March 31, 2013 and December 31, 2012, the Company would have been required to post an additional $21.3 million and $26.2 million, respectively, of collateral with its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of March 31, 2013 and December 31, 2012 is $81.9 million and $104.5 million, respectively.

In addition, as of March 31, 2013 and December 31, 2012, the Company has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments were fully triggered as of March 31, 2013 and December 31, 2012, the Company could request $45.6 million and $32.1 million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of March 31, 2013 and December 31, 2012 is $45.6 million and $32.1 million, respectively. In addition, at March 31, 2013, the Company could have called on letters of credit in the amount of $9 million related to $9 million in commodity derivatives that are in a net asset position, compared to letters of credit of $10 million related to derivatives of $13 million at December 31, 2012, if all the contingent features underlying these instruments had been fully triggered.

22

Information related to the Company's offsetting of derivative assets follows:

								Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position			Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Received		Net Amount
As of March 31, 2013
Interest rate	$	100	—			$	100	$	(22	)	—		$	78
Commodity	4		—			4		—			—		4
Energy management	10		$	(1	)	9		—			—		9
Total	$	114	$	(1	)	$	113	$	(22	)	$	—	$	91
Balance sheet location	Prepayments and other					$	66
	Other deferred debits and other assets					47
	Total					$	113

As of December 31, 2012
Interest rate	$	73	—			$	73	$	(17	)	—		$	56
Commodity	2		—			2		—			—		2
Energy management	$	13	$	(1	)	$	12	$	—		—		$	12
Total	$	88	$	(1	)	$	87	$	(17	)	$	—	$	70
Balance sheet location	Prepayments and other					$	50
	Other deferred debits and other assets					37
	Total					$	87

23

 Information related to the Company's offsetting of derivative liabilities follows:

								Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position			Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Posted			Net Amount
As of March 31, 2013
Interest rate	$	95	—			$	95	$	(22	)	$	(53	)	$	20
Commodity	1		—			1		—			—			1
Energy management	10		$	(1	)	9		—			(8		)	1
	$	106	$	(1	)	$	105	$	(22	)	$	(61	)	$	22
Balance sheet location	Other current liabilities					$	67
	Other deferred credits and other liabilities					38
	Total					$	105

As of December 31, 2012
Interest rate	$	106	—			$	106	$	(17	)	$	(67	)	$	22
Commodity	4		—			4		—			—			4
Energy management	13		$	(1	)	12		—			(11		)	1
	$	123	$	(1	)	$	122	$	(17	)	$	(78	)	$	27
Balance sheet location	Other current liabilities					$	80
	Other deferred credits and other liabilities					42
	Total					$	122

24

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 and energy management 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 market data.  Fair value measurements, and the level within the fair value hierarchyin 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 March 31, 2013
Assets -	Available for sale securities	$7	—
	Interest rate contracts	—	$100
	Commodity contracts	2	2
	Energy management contracts	1	9
Liabilities -	Interest rate contracts	—	95
	Commodity contracts	—	1
	Energy management contracts	—	13
As of December 31, 2012
Assets -	Available for sale securities	$6	—
	Interest rate contracts	—	$73
	Commodity contracts	1	1
	Energy management contracts	—	13
Liabilities -	Interest rate contracts	—	106
	Commodity contracts	—	4
	Energy management contracts	1	15

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, 2 or 3 during the periods presented.

Financial instruments for which the carrying amount may not equal estimated fair value at March 31, 2013 and December 31, 2012 were as follows:

	March 31, 2013				December 31, 2012
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	5,211.7	$	6,118.8	$	5,121.0	$	6,115.0

Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates.  As such, the aggregate fair values presented above are considered to be Level 2.  Carrying values reflect the fair values of interest rate swaps designated as fair value hedges, based on discounted cash flow models with independently sourced market data.  Early settlement of long-term debt may not be possible or may not be considered prudent.

Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2.

25

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	2013			2012			2013		2012
Three months ended March 31,
Service cost	$	5.9		$	4.8		$	1.6	$	1.3
Interest cost	9.5			10.7			2.8		3.0
Expected return on assets	(15.4		)	(14.8		)	—		—
Prior service cost amortization	1.7			1.7			0.2		0.2
Transition obligation amortization	—			—			0.2		0.2
Amortization of actuarial losses	5.4			4.7			0.8		0.2
Net periodic benefit cost	$	7.1		$	7.1		$	5.6	$	4.9

No contribution to the pension trust will be necessary until after 2014, nor will limitations on benefit payments apply.   In connection with the SCPSC's December 2012 rate order, effective January 1, 2013 SCE&G began recovering pension expense related to retail electric operations through a rate rider that is adjusted annually. As authorized by the SCPSC, prior to January 1, 2013 SCE&G deferred all pension expense related to retail electric operations as a regulatory asset, and has deferred such costs related to gas operations during both periods presented. Costs totaling $0.6 million and $3.7 million were deferred for the three months ended March 31, 2013 and 2012, respectively. Previously deferred costs related to electric operations are being recovered as described in Note 2.

9. COMMITMENTS AND CONTINGENCIES

Nuclear Insurance

Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the Company's nuclear power plant. Price-Anderson provides funds up to $12.6 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. 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 Unit 1, would be $78.3 million per incident, but not more than $11.7 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper) with NEIL.  The policies provide coverage to Summer Station Unit 1 for property damage and outage costs up to $2.75 billion. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million in limits of accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies 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 $40.6 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power or other costs and expenses, 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 impact on the Company’s results of operations, cash flows and financial position.

26

Environmental

On April 13, 2012, the EPA issued a proposed rule to establish NSPS for GHG emissions from fossil fuel-fired electric generating units. If finalized as proposed, this rule would establish performance standards for new and modified generating units, along with emissions guidelines for existing generating units. This rule would amend the NSPS for electric generating units and establish the first NSPS for GHG emissions. Essentially, the rule would require all new fossil fuel-fired power plants to meet the carbon dioxide emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal plants could be constructed without carbon capture and sequestration capabilities. The Company is evaluating the proposed rule, but cannot predict when the rule will become final, if at all, or what conditions it may impose on the Company, if any. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

In 2005, the EPA issued the CAIR, which 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.  On July 6, 2011 the EPA issued the CSAPR.  This rule replaced 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.  CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. On August 21, 2012, the Court of Appeals vacated CSAPR and left CAIR in place. The EPA's petition for rehearing of the Court of Appeals' order has been denied. On March 29, 2013, the U.S. Solicitor General petitioned the U.S. Supreme Court to review the D.C. Circuit Court's decision on CSAPR. Air quality control installations that SCE&G and GENCO have already completed allowed the Company to comply with the reinstated CAIR.  The Company will continue to pursue strategies to comply with all applicable environmental regulations.  Any costs incurred to comply with such regulations are expected to be recoverable through rates.

In April 2012, the EPA's rule containing new standards for mercury and other specified air pollutants became effective.  The rule provides up to four years for facilities to meet the standards, and the Company's evaluation of the rule is ongoing. The Company's decision in 2012 to retire certain coal-fired units or convert them to burn natural gas and its project to build the New Units (see Note 1) along with other actions are expected to result in the Company's compliance with the EPA's rule.  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.

The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the NSPS of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement. Though the Company cannot predict what action, if any, the EPA will initiate against it, any costs incurred are expected to be recoverable through rates.

The Company 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.  Environmental liabilities are accrued when the criteria for loss contingencies are met. 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.  Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are recorded to expense.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of byproduct chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA.  SCE&G anticipates that major remediation activities at all these sites will continue until 2016 and will cost an additional $22.1 million, which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.  At March 31, 2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $38.3 million and are included in regulatory assets.

27

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 approximately $3.0 million, the estimated remaining liability at March 31, 2013. PSNC Energy expects to recover through rates any cost allocable to PSNC Energy arising from the remediation of these sites.

New Nuclear Construction

SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $6.0 billion for plant costs and for related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC. There are 146 milestones for purposes of reporting the construction schedule of the New Units to the SCPSC.  The delayed schedule for the fabrication and delivery of sub-modules is a focus area of the construction of the New Units.  SCE&G is devoting resources to monitor this focus area, including mitigation options, due to the potential to affect the construction schedule. The first New Unit is scheduled for substantial completion in 2017, and the second in 2018.

The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude.  During the course of activities under the EPC Contract, issues have materialized that impact project budget and schedule. Claims specifically relating to COL delays,

design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock

conditions at the site resulted in assertions of contractual entitlement to recover additional costs to be incurred. The resolution

of these specific claims is discussed in Note 2. SCE&G expects to resolve any disputes that arise in the future through both the

informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as

well as other costs identified from time to time, will be recoverable through rates.

When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units.  In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation, as well as a request for information related to emergency plant staffing.  These conditions and requirements are responsive to the NRC's Near-Term Task Force report titled “Recommendations for Enhancing Reactor Safety in the 21st Century.”  This report was prepared in the wake of the March 2011 earthquake-generated tsunami, which severely damaged several nuclear generating units and their back-up cooling systems in Japan.  SCE&G continues to evaluate the impact these conditions and requirements impose on the construction and operation of the New Units, and SCE&G is preparing an integrated response plan to submit to the NRC for the New Units.  SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New 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. 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, net income is not allocated to the Electric Operations and Gas Distribution segments.  The Company uses net income to measure profitability for its Retail Gas Marketing and Energy Marketing segments.  Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy which meet 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.

28

Millions of dollars	External Revenue			Intersegment Revenue			Operating Income		Net Income
Three Months Ended March 31, 2013
Electric Operations	$	583		$	2		$	153	n/a
Gas Distribution	379			—			93		n/a
Retail Gas Marketing	179			—			—		$	22
Energy Marketing	167			42			—		3
All Other	12			107			7		3
Adjustments/Eliminations	(9		)	(151		)	40		123
Consolidated Total	$	1,311		—			$	293	$	151

Three Months Ended March 31, 2012
Electric Operations	$	545		$	2		$	127	n/a
Gas Distribution	274			—			83		n/a
Retail Gas Marketing	153			—			n/a		$	11
Energy Marketing	132			26			n/a		2
All Other	11			106			7		5
Adjustments/Eliminations	(8		)	(134		)	21		103
Consolidated Total	$	1,107		$	—		$	238	$	121

	March 31,		December 31,
Segment Assets	2013		2012
Electric Operations	$	9,111	$	8,989
Gas Distribution	2,308		2,292
Retail Gas Marketing	188		153
Energy Marketing	129		122
All Other	1,455		1,415
Adjustments/Eliminations	1,566		1,645
Consolidated Total	$	14,757	$	14,616

29

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTSOF 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, 2012.

RESULTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2013

AS COMPARED TO THE CORRESPONDING PERIOD IN 2012

Earnings Per Share

Earnings per share was as follows:

	2013	2012
Basic earnings per share	$1.13	$0.93
Diluted earnings per share	$1.11	$0.91

Basic earnings per share increased due to higher electric margin of $.14 and higher gas margin of $.16. These increases were partially offset by higher operating expenses of $.01, higher depreciation expense of $.02, higher property taxes of $.01, higher interest expense of $.01, dilution from additional shares outstanding of $.03 and $.02 due to other items.

Diluted earnings per share figures give effect to dilutive potential common stock using the treasury stock method. See Note 1 to the condensed consolidated financial statements.

Dividends Declared

SCANA’s Board of Directors has declared the following dividends on common stock during 2013:

Declaration Date	Dividend Per Share	Record Date	Payment Date
February 20, 2013	$0.5075	March 11, 2013	April 1, 2013
April 25, 2013	$0.5075	June 10, 2013	July 1, 2013

When a dividend payment date falls on a weekend or holiday, the payment is made the following business day.

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:

Millions of dollars	2013		% Change		2012
Operating revenues	$	585.6	7.0	%	$	547.4
Less:  Fuel used in generation	187.7		2.7	%	182.7
Purchased power	7.0		22.8	%	5.7
Margin	$	390.9	8.9	%	$	359.0

Electric margin increased by $13.0 million due to base rate increases under the BLRA, by $16.9 million due to higher retail electric base rates approved in the December 2012 rate order and by $1.5 million due to customer growth.

30

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

Classification	2013	% Change		2012
Residential	1,858	9.9	%	1,691
Commercial	1,669	1.5	%	1,644
Industrial	1,403	1.3	%	1,385
Other	134	(0.7	)%	135
Total Retail Sales	5,064	4.3	%	4,855
Wholesale	264	(58.4	)%	634
Total Sales	5,328	(2.9	)%	5,489

Retail sales volume increased primarily due to customer growth and the effects of weather. The decrease in wholesale sales is primarily due to the expiration of a customer contract.

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:

Millions of dollars	2013		% Change		2012
Operating revenues	$	379.3	38.1	%	$	274.6
Less:  Gas purchased for resale	222.7		73.2	%	128.6
Margin	$	156.6	7.3	%	$	146.0

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

Classification (in thousands)	2013	% Change		2012
Residential	21,375	42.3	%	15,026
Commercial	10,758	28.6	%	8,366
Industrial	6,161	13.1	%	5,446
Transportation	11,200	9.6	%	10,223
Total	49,494	26.7	%	39,061

Gas margin at SCE&G increased primarily due to the SCPSC-approved increase in retail gas base rates under the RSA which became effective with the first billing cycle of November 2012. Margin at PSNC Energy increased by $1.5 million primarily due to residential customer growth of approximately 2.1% as well as increased industrial usage.  Total sales volumes increased due to the effects of weather.

Retail Gas Marketing

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

Millions of dollars	2013		% Change		2012
Operating revenues	$	179.0	17.1	%	$	152.8
Net Income	22.1		99.1	%	11.1

Changes in operating revenues and net income are primarily due to higher demand in 2013 following the abnormally mild weather in 2012.

31

Energy Marketing

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

Millions of dollars	2013		% Change		2012
Operating revenues	$	209.1	32.2	%	$	158.2
Net Income	2.7		58.8	%	1.7

Operating revenues increased due to higher sales volume and higher market prices.  Net income increased due to an increase in industrial customer consumption.

Other Operating Expenses

Other operating expenses were as follows:

Millions of dollars	2013		% Change		2012
Other operation and maintenance	$	176.1	0.5	%	$	175.2
Depreciation and amortization	93.3		5.2	%	88.7
Other taxes	54.8		4.2	%	52.6

Other operation and maintenance expenses increased by $4.3 million due to incremental expenses associated with the December 2012 rate order. These increases were partially offset by lower generation expenses of $3.3 million. Depreciation and amortization expense increased $3.3 million due to the recognition of depreciation expense associated with the Wateree Station scrubber which was provided for in the December 2012 rate order and due to net plant 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, the activities of certain non-regulated subsidiaries and 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), both of which have the effect of increasing reported net income. 

Interest Expense

Interest charges increased primarily due to increased borrowings and due to the reversal in 2012 of interest which had been accrued in 2011 related to a tax uncertainty that was resolved.

Income Taxes

Income taxes for the three months ended March 31, 2013 were higher than the same period in 2012 primarily due to higher income. The increase in the effective tax rate in 2013 is principally attributable to lower recognition of EIZ Credits upon the completion of the amortization of certain such credits in 2012.

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its contractual cash obligations will be met through internally generated funds, the incurrence of additional short- and long-term indebtedness and sales of equity securities.  The Company expects that, barring 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 three and 12 months ended March 31, 2013 was 3.86 and 3.08, respectively.

32

The Company is obligated with respect to an aggregate of $67.8 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 2014.

At March 31, 2013, the Company had net available liquidity of approximately $1.3 billion. The Company's credit agreements were amended and extended in October 2012 and expire in October 2017. In connection with the amendment and extension of the agreements, Fuel Company's credit agreement was increased to $500 million, and the other companies' credit agreements remained the same size. In addition, SCE&G entered into a new three-year credit agreement in the amount of $200 million, which is scheduled to expire in October 2015. The amended and extended credit agreements, together with SCE&G's new three-year credit agreement, total an aggregate of $1.8 billion. The Company regularly monitors the commercial paper and short-term credit markets to optimize the timing of repayment of outstanding balances on its draws, if any, from the credit facilities.  The Company’s long-term debt portfolio has a weighted average maturity of approximately 17 years and bears an average interest cost of 5.9%.  Substantially all of the long-term debt 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.

SCE&G has obtained FERC authority to issue short-term indebtedness and to assume liabilities as a guarantor (pursuant to Section 204 of the Federal Power Act). SCE&G may issue unsecured promissory notes, commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, bankers, and dealers in commercial paper in amounts not to exceed $600 million. GENCO has obtained FERC authority to issue short-term indebtedness not to exceed $150 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2014.

SCANA issued $25 million of stock during the three months ended March 31, 2013 through various compensation and dividend reinvestment plans.  Similar issuances are expected in future quarters. In addition, on March 5, 2013, SCANA settled all forward sales contracts related to its common stock through the issuance of approximately 6.6 million common shares, resulting in net proceeds of approximately $196.2 million.

OTHER MATTERS

For information related to environmental matters, nuclear generation, 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, 2012. Interest rates on substantially all 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.

Commodity price risk - The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  The SCPSC authorized the suspension of SCE&G's natural gas hedging program in January 2012. The fair value of SCE&G's derivative instruments remaining to be settled were not significant for any period presented. 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 MMBTU.  Fair value represents quoted market prices for these or similar instruments.

33

	Expected Maturity			Expected Maturity
Futures - Long	2013	2014	Options Purchased Call - Long	2013	2014
Settlement Price (a)	4.12	4.27	Strike Price (a)	3.95	4.04
Contract Amount (b)	8.0	2.8	Contract Amount (b)	11.1	8.2
Fair Value (b)	8.9	2.9	Fair Value (b)	1.3	1.2
(a)  Weighted average, in dollars
(b)  Millions of dollars

	Expected Maturity
Swaps	2013	2014	2015	2016	2017
Commodity Swaps:
Pay fixed/receive variable (b)	30.4	20.6	13.7	8.2	0.5
Average pay rate (a)	4.4981	4.6906	5.1714	4.8861	4.2850
Average received rate (a)	4.1520	4.2718	4.3037	4.3836	4.5145
Fair value (b)	28.0	18.7	11.4	7.4	0.5
Pay variable/receive fixed (b)	17.7	14.8	11.4	7.4	0.5
Average pay rate (a)	4.1307	4.2354	4.3037	4.3836	4.5231
Average received rate (a)	4.5587	4.8734	5.1807	4.8925	4.2900
Fair value (b)	19.6	17.1	13.7	8.2	0.5
Basis Swaps:
Pay variable/receive variable (b)	7.6	—	—	—	—
Average pay rate (a)	4.1311	—	—	—	—
Average received rate (a)	4.1201	—	—	—	—
Fair value (b)	7.6	—	—	—	—
(a) Weighted average, in dollars
(b) Millions of dollars

ITEM 4. CONTROLS AND PROCEDURES

As of March 31, 2013, 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 March 31, 2013, 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 March 31, 2013 that has materially affected or is reasonably likely to materially affect SCANA’s internal control over financial reporting.

34

SOUTH CAROLINA ELECTRIC & GAS COMPANY

FINANCIAL SECTION

35

Item 1. FINANCIAL STATEMENTS

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

Millions of dollars	March 31, 2013			December 31, 2012
Assets
Utility Plant In Service	$	10,161		$	10,096
Accumulated Depreciation and Amortization	(3,371		)	(3,322		)
Construction Work in Progress	2,227			2,073
Plant to be Retired, Net	359			362
Nuclear Fuel, Net of Accumulated Amortization	251			166
Utility Plant, Net ($626 and $640 related to VIEs)	9,627			9,375
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	56			57
Assets held in trust, net - nuclear decommissioning	97			94
Other investments	2			3
Nonutility Property and Investments, Net	155			154
Current Assets:
Cash and cash equivalents	12			51
Receivables, net of allowance for uncollectible accounts of $3 and $3	456			483
Affiliated receivables	9			2
Inventories (at average cost):
Fuel and gas supply	179			203
Materials and supplies	129			126
Emission allowances	1			1
Prepayments and other	148			143
Total Current Assets ($184 and $206 related to VIEs)	934			1,009
Deferred Debits and Other Assets:
Regulatory assets	1,365			1,377
Other	197			189
Total Deferred Debits and Other Assets ($58 and $54 related to VIEs)	1,562			1,566
Total	$	12,278		$	12,104

36

Millions of dollars	March 31, 2013		December 31, 2012
Capitalization and Liabilities
Common equity	$	4,177	$	3,929
Noncontrolling interest	115		114
Long-Term Debt, net	3,646		3,557
Total Capitalization	7,938		7,600
Current Liabilities:
Short-term borrowings	408		449
Current portion of long-term debt	165		165
Accounts Payable	208		281
Affiliated Payables	128		124
Customer deposits and customer prepayments	53		51
Taxes accrued	70		151
Interest accrued	51		63
Dividends declared	64		46
Derivative financial instruments	59		66
Other	30		50
Total Current Liabilities	1,236		1,446
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,491		1,479
Deferred investment tax credits	35		36
Asset retirement obligations	540		535
Postretirement benefits	254		254
Regulatory liabilities	697		665
Other	87		89
Total Deferred Credits and Other Liabilities	3,104		3,058
Commitments and Contingencies (Note 9)	—		—
Total	$	12,278	$	12,104

See Notes to Condensed Consolidated Financial Statements.

37

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited) 

	Three Months Ended
	March 31,
Millions of dollars	2013			2012
Operating Revenues:
Electric	$	585		$	547
Gas	143			116
Total Operating Revenues	728			663
Operating Expenses:
Fuel used in electric generation	188			183
Purchased power	7			6
Gas purchased for resale	77			59
Other operation and maintenance	138			138
Depreciation and amortization	77			73
Other taxes	50			48
Total Operating Expenses	537			507
Operating Income	191			156
Other Expense:				156,311,000
Interest charges, net of allowance for borrowed funds used during construction of $2 and $2	(55		)	(51		)
Allowance for equity funds used during construction	4			3
Other expense	(4		)	(4		)
Total Other Expense	(55		)	(52		)
Income Before Income Tax Expense	136			104
Income Tax Expense	44			32
Net Income	92			72
Net Income Attributable to Noncontrolling Interest	(3		)	(3		)
Earnings Available to Common Shareholder	$	89		$	69
Dividends Declared on Common Stock	$	64		$	53

See Notes to Condensed Consolidated Financial Statements.

38

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
Millions of dollars	2013			2012
Net Income	$	92		$	72
Other Comprehensive Income, net of tax:
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax of $- and $-	—			—
Total Comprehensive Income	92			72
Comprehensive income attributable to noncontrolling interest	(3		)	(3		)
Comprehensive income available to common shareholder	$	89		$	69

Accumulated other comprehensive loss totaled $3.9 million as of March 31, 2013 and $4.0 million as of December 31, 2012.

See Notes to Condensed Consolidated Financial Statements.

39

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
Millions of dollars	2013			2012
Cash Flows From Operating Activities:
Net income	$	92		$	72
Adjustments to reconcile net income to net cash provided from operating activities:
Losses from equity method investments	1			1
Deferred income taxes, net	12			44
Depreciation and amortization	78			73
Amortization of nuclear fuel	13			13
Allowance for equity funds used during construction	(4		)	(3		)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	(7		)	28
Inventories	10			(38		)
Prepayments and other	(12		)	2
Regulatory assets	11			41
Regulatory liabilities	27			1
Accounts payable	4			15
Taxes accrued	(81		)	(80		)
Interest accrued	(12		)	(3		)
Changes in other assets	(21		)	(1		)
Changes in other liabilities	(21		)	(78		)
Net Cash Provided From Operating Activities	90			87
Cash Flows From Investing Activities:
Property additions and construction expenditures	(264		)	(295		)
Proceeds from investments (including derivative collateral posted)	81			52
Purchase of investments (including derivative collateral posted)	(70		)	(50		)
Proceeds from interest rate contract settlement	—			13
Net Cash Used For Investing Activities	(253		)	(280		)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	57			248
Repayment of long-term debt	(66		)	(8		)
Dividends	(46		)	(39		)
Contributions from parent	221			24
Short-term borrowings –affiliate, net	(1		)	20
Short-term borrowings, net	(41		)	(44		)
Net Cash Provided From Financing Activities	124			201
Net Increase (Decrease) In Cash and Cash Equivalents	(39		)	8
Cash and Cash Equivalents, January 1	51			16
Cash and Cash Equivalents, March 31	$	12		$	24
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $2 and $2)	$	62		$	51
Noncash Investing and Financing Activities:
Accrued construction expenditures	81			103
Capital leases	1			—
Nuclear fuel purchase	97			—

See Notes to Condensed Consolidated Financial Statements.

40

SOUTH CAROLINA ELECTRIC & GAS COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the Three Months Ended March 31, 2013 and 2012

(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, 2012.  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

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.

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, pursuant to a FERC-approved tariff, 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 $472 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances. See also Note 4.

Plant to be Retired

SCE&G has six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units have an aggregate generating capacity (summer 2012) of 730 MW. One unit (90 MW) has been retired and its value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units totaled $359 million at March 31, 2013 and is included in Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.

2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G's retail electric rates include 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. In April 2012, the SCPSC approved SCE&G's request to decrease the total fuel cost component of its retail electric rates, and approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to recover an amount equal to its actual under-collected balance of

41

base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a 12-month period beginning with the first billing cycle of May 2012.

In the December 2012 rate order, the SCPSC authorized SCE&G to reduce the base fuel cost component of its retail electric rates and in doing so, stated that SCE&G may not adjust its base fuel component prior to April 1, 2014, except where necessary due to extraordinary unforeseen economic or financial conditions.  In February 2013, in connection with its annual review of base rates for fuel costs, SCE&G requested authorization to reduce its environmental fuel cost component effective with the first billing cycle of May 2013.  Consistent with the December 2012 rate order, however, SCE&G did not request any adjustment to its base fuel cost component.  On March 14, 2013 SCE&G, ORS and the SCEUC entered into a settlement agreement accepting the proposed lower environmental fuel cost component effective the first billing cycle of May 2013.  By not adjusting SCE&G's base fuel component, the settlement also provided for carrying costs on a portion of the undercollected balance of fuel costs.  The SCPSC approved this settlement agreement on April 10, 2013.

On December 19, 2012, the SCPSC approved a 4.23% overall increase in SCE&G's retail electric base rates, effective January 1, 2013, and authorized an allowed return on common equity of 10.25%. The SCPSC also approved a mid-period reduction to the cost of fuel component in rates, a reduction in the DSM Programs component rider to retail rates, and the recovery of and a return on the net carrying value of certain retired generating plant assets described below. By order dated February 7, 2013, the SCPSC denied the SCEUC's petition for rehearing of this order.

The eWNA is designed to reduce volatility of costs charged to residential and commercial customers due to abnormal weather and is based on a 15 year historical average of temperatures. In connection with the December 2012 rate order, SCE&G agreed to perform a study of alternative structures for eWNA by June 30, 2013, which may be used to modify or terminate eWNA in the future.

In February 2013, SCE&G filed an IRP with the SCPSC. The IRP evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. The IRP identified a total of six coal-fired units that SCE&G intends to retire by 2018, subject to future developments in environmental regulations, among other matters. The net carrying value of a unit that has been retired is recorded in regulatory assets as unrecovered plant and is being amortized over its original remaining useful life as further described below. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.

SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and lost net margin revenue associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G submits annual filings in January to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC has approved the following rate changes pursuant to annual DSM Programs filings, which changes went into effect as indicated below:

Year	Effective	Amount
2012	First billing cycle of May	$19.6 million
2011	First billing cycle of June	$7.0 million

In January 2013, SCE&G filed its annual update on DSM Programs and a petition for an update to the rate rider, requesting an increase of approximately $27.2 million. On April 1, 2013, ORS filed a report of its review of SCE&G's DSM Programs petition with the SCPSC. ORS proposed that SCE&G recover the net lost revenue component of the rider of $20.6 million over a 24-month period effective for bills rendered on and after the first billing cycle in May 2013. ORS also recommended that SCE&G defer a portion of net lost revenue component in a regulatory asset and recover those amounts over a 12-month period effective for bills rendered on and after the first billing cycle in May 2014. SCE&G agreed with ORS's recommendations. In April 2013, the SCPSC approved SCE&G's request to update its rider as modified by the agreement between ORS and SCE&G.

Electric – BLRA

In November 2012, the SCPSC approved an updated construction schedule and additional updated capital costs of $278 million (SCE&G's portion in 2007 dollars). The November 2012 order approved additional identifiable capital costs of

42

approximately $1 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications; approximately $8 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure; and approximately $132 million (SCE&G's portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. In addition, the order approved revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims for costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals.

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 11.0%. The SCPSC has approved the following rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated:

Year	Action			Amount
2012	2.3	%	Increase	$52.1 million
2011	2.4	%	Increase	$52.8 million

Gas

The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the years indicated:

Year	Action			Amount
2012	2.1	%	Increase	$7.5 million
2011	2.1	%	Increase	$8.6 million

SCE&G's natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. SCE&G's gas rates are calculated using a methodology which may adjust 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 held in November 2012 before the SCPSC. The SCPSC issued an order in December 2012 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2011 through July 31, 2012, were reasonable and prudent.

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 regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.

43

Millions of dollars	March 31, 2013		December 31, 2012
Regulatory Assets:
Accumulated deferred income taxes	$	248	$	248
Under collections – electric fuel adjustment clause	75		66
Environmental remediation costs	38		39
AROs and related funding	307		304
Franchise agreements	34		36
Deferred employee benefit plan costs	399		405
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	141		151
Deferred pollution control costs	38		38
Unrecovered plant	20		20
Other	65		64
Total Regulatory Assets	$	1,365	$	1,377

Regulatory Liabilities:
Accumulated deferred income taxes	$	20	$	21
Asset removal costs	512		507
Storm damage reserve	27		27
Deferred gains on interest rate derivatives	137		110
Planned major maintenance	1		—
Total Regulatory Liabilities	$	697	$	665

Accumulated deferred income tax liabilities that arose from utility operations that have not been included in customer rates are recorded as a regulatory asset.  Substantially all of these regulatory assets relate to depreciation and 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 not expected to be recovered in retail electric rates within 12 months. 

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 periods of up to approximately 28 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. In connection with the December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are to be recovered through utility rates over approximately 30 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 12 years.

44

Planned major maintenance related to certain fossil fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders.  SCE&G collects $18.4 million annually for fossil fueled turbine/generation equipment maintenance.  Through December 31, 2012, nuclear refueling charges were accrued during each 18-month refueling outage cycle as a component of cost of service. In connection with the December 2012 rate order, effective January 1, 2013, SCE&G began to collect and accrue $17.2 million annually for nuclear-related refueling charges.

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.

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at Wateree and Williams Stations pursuant to specific regulatory orders.  Such costs will be recovered through utility rates over periods up to 30years. 

Unrecovered plant represents the net book value of a coal-fired generating unit retired from service prior to being fully depreciated. Pursuant to the December 2012 rate order, SCE&G is amortizing these amounts over the unit's original remaining useful life of approximately 14 years. Unamortized amounts are included in rate base.

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. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely.

The SCPSC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been approved for recovery by the SCPSC or by the FERC. In recording such 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. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. 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 effect on Consolidated SCE&G's results of operations, liquidity or financial position in the period the write-off would be recorded.

3. EQUITY

Changes in common equity during the three months ended March 31, 2013 and 2012 were as follows:

Millions of dollars	Common Equity			Noncontrolling Interest			Total Equity
Balance at January 1, 2013	$	3,929		$	114		$	4,043
Capital contribution from parent	221			—			221
Dividends declared	(62		)	(2		)	(64		)
Comprehensive income	89			3			92
Balance as of March 31, 2013	$	4,177		$	115		$	4,292
Balance at January 1, 2012	$	3,665		$	108		$	3,773
Capital contribution from parent	24			—			24
Dividends declared	(51		)	(2		)	(53		)
Comprehensive income	69			3			72
Balance as of March 31, 2012	$	3,707		$	109		$	3,816

45

SCE&G had 50 million shares of common stock authorized as of March 31, 2013 and December 31, 2012, of which 40.3 million were issued and outstanding during all periods presented. SCE&G had 20 million shares of preferred stock authorized as of March 31, 2013 and December 31, 2012, of which 1,000 shares were issued and outstanding during all periods presented. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA.

Reclassifications from AOCI into earnings of the amortization of deferred employee benefit costs were not significant for any period presented.

4. LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In January 2013, JEDA issued at a premium, for the benefit of SCE&G, $39.5 million of 4.0% tax-exempt industrial revenue bonds due February 1, 2028, and $14.7 million of 3.63% tax-exempt industrial revenue bonds due February 1, 2033. Proceeds from these sales were loaned by JEDA to SCE&G and, together with other available funds, were used to redeem prior to maturity $56.9 million of 5.2% industrial revenue bonds due November 1, 2027.

 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:

Millions of dollars	March 31, 2013			December 31, 2012
Lines of credit:
Total committed long-term	$	1,400		$	1,400
LOC advances	—			—
Weighted average interest rate	—			—
Outstanding commercial paper (270 or fewer days)	$	408		$	449
Weighted average interest rate	0.33		%	0.42		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	992		$	951

SCE&G and Fuel Company are parties to five-year credit agreements in the amount of $1.2 billion (of which $500 million relates to Fuel Company) which expire in October 2017. In addition, SCE&G is party to a new three-year credit agreement in the amount of $200 million, which expires in October 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, certain fossil fuels, 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 10.7% of the aggregate $1.4 billion credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch and UBS Loan Finance LLC each provide 8.9% and Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 6.3%.  Two other banks provide the remaining support. Consolidated SCE&G pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented.

Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company.  The letters of credit expire, subject to renewal, in the fourth quarter of 2014.

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 any period presented. At March 31, 2013 and December 2012, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $48.8 million and $49.4 million, respectively.

46

5. INCOME TAXES

In connection with a prior change in method of tax accounting for certain repair costs, Consolidated SCE&G had previously recorded an unrecognized tax benefit of $38 million. Under newadministrative guidance from the Internal Revenue Service, Consolidated SCE&G recognized all of the previously unrecognized tax benefit in the first quarter of 2012. Since this change was primarily a temporary difference, the recognition of this benefit did not have a significant effect on Consolidated SCE&G's effective tax rate. No other material changes in the status of Consolidated SCE&G's tax positions have occurred through March 31, 2013.

Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. In connection with the resolution of the uncertainty and recognition of tax benefits described above, during the quarter ended March 31, 2012, Consolidated SCE&G reversed $2 million of interest expense which had been accrued during 2011. 

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. 

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 Audit Committee of the Board of Directors with regard to the management of risk and brings to the Audit Committee’s attention significant areas of concern.  Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

Interest Rate Swaps

Consolidated SCE&G synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges.  Periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

In anticipation of the issuance of debt, Consolidated SCE&G may use treasury rate lock or forward starting swap agreements that are designated as cash flow hedges.  The effective portions of changes in fair value and payments made or received upon termination of such agreements are recorded in regulatory assets or regulatory liabilities.  Such amounts are amortized to interest expense over the term of the underlying debt.  Ineffective portions are recognized in income.  Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes.

Quantitative Disclosures Related to Derivatives

Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $971.4 million at each of March 31, 2013 and December 31, 2012.

The fair value of interest rate derivatives was reflected in the condensed consolidated balance sheet as follows:

	Fair Values of Derivative Instruments
	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
Millions of dollars	Location	Value		Location	Value
As of March 31, 2013
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	58	Other current liabilities	$	59
	Other deferred debits and other assets	42		Other deferred credits and other liabilities	7
Total		$	100		$	66
As of December 31, 2012
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	42	Other current liabilities	$	66
	Other deferred debits and other assets	31		Other deferred credits and other liabilities	9
Total		$	73		$	75

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

Derivatives in Cash Flow Hedging Relationships	Gain Deferred in Regulatory Accounts				Loss Reclassified from Deferred Accounts into Income (Effective Portion)
Millions of dollars	(Effective Portion)				Location	Amount
Three Months Ended March 31,	2013		2012			2013			2012
Interest rate	$	35	$	30	Interest expense	$	(1	)	$	(1	)

Derivatives not designated as Hedging Instruments	Loss Recognized in Income
Millions of dollars	Location	2013	2012
Three Months Ended March 31,
Commodity	Gas purchased for resale	—	(1	)

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 months ended March 31, 2013 and 2012, respectively.

Credit Risk Considerations

Consolidated SCE&G limits credit risk in its derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. In this regard, Consolidated SCE&G uses credit ratings provided by credit rating agencies and current market-based qualitative and quantitative data as well as financial statements, to assess the financial health of counterparties on an ongoing basis. Consolidated SCE&G uses standardized master agreements which may include collateral requirements. These master agreements permit the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements (if any) require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with Consolidated SCE&G's credit policies and due diligence. In addition, collateral agreements (if any) allow for the termination and liquidation of all positions in the event of a failure or inability to post collateral.

Certain of Consolidated SCE&G’s derivative instruments contain contingent provisions that require Consolidated SCE&G to provide collateral upon the occurrence of specific events, primarily credit downgrades.  As of March 31, 2013 and December 31, 2012, Consolidated SCE&G has posted $22.1 million and $35.2 million, respectively, of collateral related to derivatives with contingent provisions that were in a net liability position.  Collateral related to the positions expected to close in the next 12 months are recorded in Prepayments and other on the consolidated balance sheets. Collateral related to the noncurrent positions are recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of March 31, 2013 and December 31, 2012, Consolidated SCE&G would have been required to post an additional $22.2 million and $22.7 million respectively, of collateral with its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of March 31, 2013 and December 31, 2012 is $44.3 million and $57.9 million, respectively.

In addition, as of March 31, 2013 and December 31, 2012, Consolidated SCE&G has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments were fully triggered as of March 31, 2013 and December 31, 2012, Consolidated SCE&G could request $43.9 million and $32.1 million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of March 31, 2013 and December 31, 2012 is $43.9 million and $32.1 million, respectively.

Information related to Consolidated SCE&G's derivative assets follows:

						Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Received	Net Amount
As of March 31, 2013
Interest rate	$	100	—	$	100	$	(22	)	—	$	78
Balance Sheet Location	Prepayments and other			$	58
	Other deferred debits and other assets			42
	Total			$	100

As of December 31, 2012
Interest rate	$	73	—	$	73	(17	)	—	$	56
Balance Sheet Location	Prepayments and other			$	42
	Other deferred debits and other assets			31
	Total			$	73

Information related to Consolidated SCE&G's derivative liabilities follows:

						Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Posted			Net Amount
As of March 31, 2013
Interest rate	$	66	—	$	66	$	(22	)	$	(22	)	$	22
Balance Sheet Location	Other current liabilities			$	59
	Other deferred credits and other liabilities			7
	Total			$	66

As of December 31, 2012
Interest rate	$	75	—	$	75	$	(17	)	$	(35	)	$	23
Balance Sheet Location	Other current liabilities			$	66
	Other deferred credits and other liabilities			9
	Total			$	75

7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

Consolidated SCE&G’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data.  Fair value measurements based on significant other observable inputs (level 2) were as follows: 

		Fair Value Measurements Using Significant
		Other Observable Inputs (Level 2)
Millions of dollars		March 31, 2013	December 31, 2012
Assets -	Interest rate contracts	$100	$73
Liabilities -	Interest rate contracts	66	75

There were no fair value measurements based on quoted prices in active markets for identical assets (Level 1) or 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, 2 or 3 during the periods presented.

Financial instruments for which the carrying amount may not equal estimated fair value at March 31, 2013 and December 31, 2012 were as follows:

	March 31, 2013				December 31, 2012
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,811.0	$	4,534.8	$	3,722.0	$	4,543.1

Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates.  As such, the aggregate fair values presented above are considered to be Level 2.  Carrying values reflect the fair values of interest rate swaps designated as fair value hedges, based on discounted cash flow models with independently sourced market data.  Early settlement of long-term debt may not be possible or may not be considered prudent.

47

Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2.

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	2013			2012			2013		2012
Three months ended March 31,
Service cost	$	4.8		$	3.9		$	1.2	$	1.0
Interest cost	8.0			9.1			2.2		2.4
Expected return on assets	(13.0		)	(12.6		)	—		—
Prior service cost amortization	1.4			1.4			0.2		0.2
Amortization of actuarial losses	4.6			4.0			0.6		0.1
Net periodic benefit cost	$	5.8		$	5.8		$	4.2	$	3.7

No contribution to the pension trust will be necessary until after 2014, nor will limitations on benefit payments apply.  In connection with the SCPSC's December 2012 rate order, effective January 1, 2013 SCE&G began recovering pension expense related to retail electric operations through a rate rider that is adjusted annually. As authorized by the SCPSC, prior to January 1, 2013 SCE&G deferred all pension expense related to retail electric operations as a regulatory asset, and has deferred such costs related to gas operations during both periods presented. Costs totaling $0.6 million and $3.7 million were deferred for the three months ended March 31, 2013 and 2012, respectively. Previously deferred cost related to electric operations are being recovered as described in Note 2.

9. COMMITMENTS AND CONTINGENCIES

 Nuclear Insurance

Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the Company's nuclear power plant. Price-Anderson provides funds up to $12.6 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. 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 Unit 1, would be $78.3 million per incident, but not more than $11.7 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper) with NEIL.  The policies provide coverage to Summer Station Unit 1 for property damage and outage costs up to $2.75 billion. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million in limits of accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies 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 $40.6 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station Unit 1 exceed the policy limits of insurance, or to the extent such

48

insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power or other cost and expenses, 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 impact on the Company’s results of operations, cash flows and financial position.

Environmental

On April 13, 2012, the EPA issued a proposed rule to establish NSPS for GHG emissions from fossil fuel-fired electric generating units. If finalized as proposed, this rule would establish performance standards for new and modified generating units, along with emissions guidelines for existing generating units. This rule would amend the NSPS for electric generating units and establish the first NSPS for GHG emissions. Essentially, the rule would require all new fossil fuel-fired power plants to meet the carbon dioxide emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal plants could be constructed without carbon capture and sequestration capabilities. Consolidated SCE&G is evaluating the proposed rule, but cannot predict when the rule will become final, if at all, or what conditions it may impose on Consolidated SCE&G, if any.  Consolidated SCE&G expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

In 2005, the EPA issued the CAIR, which 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. On July 6, 2011 the EPA issued the CSAPR.  This rule replaced 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.  CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. On August 21, 2012, the Court of Appeals vacated CSAPR and left CAIR in place. The EPA's petition for rehearing of the Court of Appeals' order has been denied. On March 29, 2013, the U.S. Solicitor General petitioned the U. S. Supreme Court to review the D.C. Circuit Court's decision on CSAPR. Air quality control installations that SCE&G and GENCO have already completed allowed Consolidated SCE&G to comply with the reinstated CAIR.  Consolidated SCE&G will continue to pursue strategies to comply with all applicable environmental regulations.  Any costs incurred to comply with such regulations are expected to be recoverable through rates.

In April 2012, the EPA's rule containing new standards for mercury and other specified air pollutants became effective.  The rule provides up to four years for facilities to meet the standards, and Consolidated SCE&G's evaluation of the rule is ongoing. Consolidated SCE&G's decision in 2012 to retire certain coal-fired units or convert them to burn natural gas and its project to build the New Units (see Note 1) along with other actions are expected to result in Consolidated SCE&G's compliance with the EPA's rule.  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.

The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the NSPS of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement. Though Consolidated SCE&G cannot predict what action, if any, the EPA will initiate against it, any costs incurred are expected to be recoverable through rates.

Consolidated 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.  Environmental liabilities are accrued when the criteria for loss contingencies are met. 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.  Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are recorded to expense.

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 and the EPA.  SCE&G anticipates that major remediation activities at all these sites will continue until 2016 and will cost an

49

additional $22.1 million, which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.  At March 31, 2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $38.3 million and are included in regulatory assets.

New Nuclear Construction

SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $6.0 billion for plant costs and for related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC. There are 146 milestones for purposes of reporting the construction schedule of the New Units to the SCPSC.  The delayed schedule for the fabrication and delivery of sub-modules is a focus area of the construction of the New Units.  SCE&G is devoting resources to monitor this focus area, including mitigation options, due to the potential to affect the construction schedule. The first New Unit is scheduled for substantial completion in 2017, and the second in 2018.

The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude.  During the course of activities under the EPC Contract, issues have materialized that impact project budget and schedule. Claims specifically relating to COL delays,

design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock

conditions at the site resulted in assertions of contractual entitlement to recover additional costs to be incurred. The resolution

of these specific claims is discussed in Note 2. SCE&G expects to resolve any disputes that arise in the future through both the

informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as

well as other costs identified from time to time, will be recoverable through rates.

When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units.  In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation, as well as a request for information related to emergency plant staffing.  These conditions and requirements are responsive to the NRC's Near-Term Task Force report titled “Recommendations for Enhancing Reactor Safety in the 21st Century.”  This report was prepared in the wake of the March 2011 earthquake-generated tsunami, which severely damaged several nuclear generating units and their back-up cooling systems in Japan.  SCE&G continues to evaluate the impact these conditions and requirements impose on the construction and operation of the New Units, and SCE&G is preparing an integrated response plan to submit to the NRC for the New Units.  SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New 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. 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 serve SCE&G’s retail gas customers and certain electric generation requirements.  Transportation services totaled approximately $8.4 million and $10.0 million for the three months ended March 31, 2013 and 2012, respectively.  SCE&G had approximately $3.2 million and $3.4 million payable to CGT for transportation services at March 31, 2013 and December 31, 2012, respectively.

SCE&G purchases natural gas and related pipeline capacity from SEMI to serve its retail gas customers and certain electric generation requirements.  Such purchases totaled approximately $42.1 million and $25.4 million for the three months ended March 31, 2013 and 2012, respectively.  SCE&G’s payables to SEMI for such purposes were $14.1 million and $13.1 million as of March 31, 2013 and December 31, 2012, respectively.

SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G owned 10% of Cope Refined Coal, LLC through December 31, 2012. SCE&G accounts for these investments using the equity method.  SCE&G’s receivables from these affiliates were $7.9 million at March 31, 2013 and $1.8 million at December 31, 2012.  SCE&G’s payables to these affiliates were $8.0 million at March 31, 2013 and $1.8 million at

50

December 31, 2012.  SCE&G’s total purchases from these affiliates were $14.3 million and $27.1 million for the three months ended March 31, 2013 and 2012, respectively.  SCE&G’s total sales to these affiliates were $14.3 million and $26.9 million for the three months ended March 31, 2013 and 2012, respectively.

Consolidated SCE&G receives the following services from SCANA Services and its parent company, which are rendered at direct or allocated cost: information systems services, customer services, marketing and sales, human resources, corporate compliance, purchasing, financial services, risk management, public affairs, legal services, investor relations, gas supply and capacity management, strategic planning, general administrative services, and retirement benefits. Consolidated SCE&G’s payables for such purposes were $45.2 million and $45.8 million as of March 31, 2013 and December 31, 2012, respectively.

Money pool borrowings from an affiliate are described at Note 4.

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.

					Earnings Available
	External		Operating		To Common
Millions of dollars	Revenue		Income		Shareholder
Three Months Ended March 31, 2013
Electric Operations	$	585	$	153	n/a
Gas Distribution	143		38		n/a
Adjustments/Eliminations	—		—		$	89
Consolidated Total	$	728	$	191	$	89

Three Months Ended March 31, 2012
Electric Operations	$	547	$	127	n/a
Gas Distribution	116		29		n/a
Adjustments/Eliminations	—		—		$	69
Consolidated Total	$	663	$	156	$	69

	March 31,		December 31,
Segment Assets	2013		2012
Electric Operations	$	9,111	$	8,989
Gas Distribution	664		659
Adjustments/Eliminations	2,503		2,456
Consolidated Total	$	12,278	$	12,104

51

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, 2012. 

RESULTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2013

AS COMPARED TO THE CORRESPONDING PERIOD IN 2012

Net Income

Net income for Consolidated SCE&G was as follows:

Millions of dollars	2013		% Change		2012
Net income	$	91.8	28.2	%	$	71.6

Net income increased by $21.5 million due to higher electric margin and by $6.1 million due to higher gas margin.  These increases were partially offset by higher depreciation expense of $2.8 million, higher property taxes of $1.1 million and higher interest expense of $2.8 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 2013:

Declaration Date	Amount	Quarter Ended	Payment Date
February 20, 2013	$64.0 million	March 31, 2013	April 1, 2013
April 25, 2013	$63.8 million	June 30, 2013	July 1, 2013

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:

Millions of dollars		2013		% Change		2012
Operating revenues		$	585.6	7.0	%	$	547.4
Less:	Fuel used in electric generation	187.7		2.7	%	182.7
	Purchased power	7.0		22.8	%	5.7
Margin		$	390.9	8.9	%	$	359.0

Electric margin increased by $13.0 million due to base rate increases under the BLRA, by $16.9 million due to higher retail electric base rates approved in the December 2012 rate order and by $1.5 million due to customer growth.

52

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

Classification	2013	% Change		2012
Residential	1,858	9.9	%	1,691
Commercial	1,669	1.5	%	1,644
Industrial	1,403	1.3	%	1,385
Other	134	(0.7	)%	135
Total Retail Sales	5,064	4.3	%	4,855
Wholesale	264	(58.4	)%	634
Total Sales	5,328	(2.9	)%	5,489

Retail sales volume increased primarily due to the effects of customer growth and weather. The decrease in wholesale sales is primarily due to the expiration of a customer contract.

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:

Millions of dollars	2013		% Change		2012
Operating revenues	$	142.7	23.3	%	$	115.7
Less: Gas purchased for resale	77.1		30.2	%	59.2
Margin	$	65.6	16.1	%	$	56.5

Gas margin increased primarily due to the SCPSC-approved increase in retail gas base rates under the RSA which became effective with the first billing cycle of November 2012.

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

Classification (in thousands)	2013	% Change		2012
Residential	6,459	39.8	%	4,619
Commercial	4,294	20.0	%	3,579
Industrial	5,369	10.9	%	4,843
Transportation	1,316	0.9	%	1,304
Total	17,438	21.6	%	14,345

Total sales volumes increased due primarily due to the effects of weather.

Other Operating Expenses

Other operating expenses were as follows:

Millions of dollars	2013		% Change		2012
Other operation and maintenance	$	138.4	—		$	138.4
Depreciation and amortization	77.6		6.2	%	73.1
Other taxes	49.6		4.0	%	47.7

Other operation and maintenance expenses increased by $4.3 million due to incremental expenses associated with the December 2012 rate order. These increases were partially offset by lower generation expenses of $3.3 million. Depreciation and amortization expense increased $3.3 million due to the recognition of depreciation expense associated with the Wateree Station scrubber which was provided for in the December 2012 rate order and due to net plant additions.  Other taxes increased primarily due to higher property taxes.

53

Other Expense

Other income (expense) includes the results of certain incidental (non-utility) activities and 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), both of which have the effect of increasing reported net income. 

Interest Expense

Interest charges increased primarily due to increased borrowings and due to the reversal in 2012 of interest which had been accrued in 2011 related to a tax uncertainty that was resolved.

Income Taxes

Income taxes for the three months ended March 31, 2013 were higher than the same period in 2012 primarily due to higher income. The increase in the effective tax rate in 2013 is principally attributable to lower recognition of EIZ Credits upon the completion of amortization of certain such credits in 2012.

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 three and 12 months ended March 31, 2013 was 3.38 and 3.38, respectively.

SCE&G received approximately $221 million during the three months ended March 31, 2013 as an equity contribution from its parent company.

Consolidated SCE&G is obligated with respect to an aggregate of $67.8 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 2014.

At March 31, 2013, Consolidated SCE&G had net available liquidity of approximately $1.0 billion. Consolidated SCE&G's credit agreements were amended and extended in October 2012 and expire in October 2017. In connection with the amendment and extension of the agreements, Fuel Company's credit agreement was increased to $500 million, although SCE&G's existing credit agreements remained the same size. In addition, SCE&G entered into a new three-year credit agreement in the amount of $200 million, which is scheduled to expire in October 2015. Consolidated SCE&G regularly monitors the commercial paper and short-term credit markets to optimize the timing of repayment of outstanding balances on its draws, if any, from the credit facilities.  Consolidated SCE&G’s long term debt portfolio has a weighted average maturity of approximately 19 years and bears an average interest cost of 5.9%.  Substantially all of the long-term debt 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.

SCE&G has obtained FERC authority to issue short-term indebtedness and to assume liabilities as a guarantor (pursuant to Section 204 of the Federal Power Act). SCE&G may issue unsecured promissory notes, commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, bankers, and dealers in commercial paper in amounts not to exceed $600 million. GENCO has obtained FERC authority to issue short-term indebtedness not to exceed $150 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2014.

54

OTHER MATTERS

For information related to environmental matters, nuclear generation, 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, 2012. Interest rates on substantially all 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.

ITEM 4. CONTROLS AND PROCEDURES

As of March 31, 2013, 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 March 31, 2013, 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 March 31, 2013, that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.

55

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.

56

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
Date: May 9, 2013		James E. Swan, IV
		Controller
		(Principal accounting officer)

57

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)
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

*   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.

58

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Kevin B. Marsh, 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: May 9, 2013
	/s/Kevin B. Marsh
	Kevin B. Marsh
	Chairman of the Board, President, Chief Executive Officer and
	Chief Operating Officer

61

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: May 9, 2013
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Executive Vice President and Chief Financial Officer

62

EX-31.03

Exhibit 31.03

CERTIFICATION

I, Kevin B. Marsh, 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: May 9, 2013
	/s/Kevin B. Marsh
	Kevin B. Marsh
	Chairman of the Board and Chief Executive Officer

63

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: May 9, 2013
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Executive Vice President and Chief Financial Officer

64

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 March 31, 2013 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: May 9, 2013

/s/Kevin B. Marsh

Kevin B. Marsh

Chairman of the Board, President, Chief Executive Officer

and Chief Operating 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. 

65

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 March 31, 2013 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: May 9, 2013

/s/Jimmy E. Addison

Jimmy E. Addison

Executive 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. 

66

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 March 31, 2013 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: May 9, 2013

/s/Kevin B. Marsh

Kevin B. Marsh

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. 

67

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 March 31, 2013 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: May 9, 2013

/s/Jimmy E. Addison

Jimmy E. Addison

Executive 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. 

68

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details 2) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	$ (22)	$ (17)
Asset Derivatives Fair Value	114	88
Derivative Asset Fair Value Gross Amount offset in statement of financial position	(1)	(1)
Liability Derivatives Fair Value	106	123
Derivative Liability Fair Value Gross Amount Offset in the Statement of Financial Position	(1)	(1)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(22)	(17)
Collateral Already Posted, Aggregate Fair Value	60.6	78.3
Derivative Liability, Fair Value, Net	105	122
Net Fair Value Derivative Asset offset against Collateral	91	70
Net Fair Value Derivative Liability offset against Collateral	22	27
Derivative Asset, Fair Value, Net	113	87
Prepayments and other current assets [member]
Derivative [Line Items]
Derivative Asset, Fair Value, Net	66	50
Other current liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Net	67	80
Other deferred credits and other liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Net	38	42
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Net	47	37
Derivatives designated as hedging instruments
Derivative [Line Items]
Asset Derivatives Fair Value	102	74
Liability Derivatives Fair Value	96	110
Derivatives not designated as hedging instruments
Derivative [Line Items]
Asset Derivatives Fair Value	12	14
Liability Derivatives Fair Value	10	13
Energy Management Contracts [Member]
Derivative [Line Items]
Asset Derivatives Fair Value	10	13
Derivative Asset Fair Value Gross Amount offset in statement of financial position	(1)	(1)
Liability Derivatives Fair Value	10	13
Collateral Already Posted, Aggregate Fair Value	(8.0)	(11.0)
Derivative Liability, Fair Value, Net	9	12
Net Fair Value Derivative Asset offset against Collateral	9	12
Net Fair Value Derivative Liability offset against Collateral	1	1
Derivative Asset, Fair Value, Net	9	12
Interest Rate Contract
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(22)	(17)
Asset Derivatives Fair Value	100	73
Liability Derivatives Fair Value	95	106
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(22)	(17)
Collateral Already Posted, Aggregate Fair Value	(53.0)	(67.0)
Derivative Liability, Fair Value, Net	95	106
Net Fair Value Derivative Asset offset against Collateral	78	56
Net Fair Value Derivative Liability offset against Collateral	20	22
Derivative Asset, Fair Value, Net	100	73
Interest Rate Contract | Derivatives designated as hedging instruments | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value	58	42
Interest Rate Contract | Derivatives designated as hedging instruments | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	62	70
Interest Rate Contract | Derivatives designated as hedging instruments | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	33	36
Interest Rate Contract | Derivatives designated as hedging instruments | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Asset Derivatives Fair Value	42
Commodity Contract
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0
Asset Derivatives Fair Value	4	2
Liability Derivatives Fair Value	1	4
Derivative Liability Fair Value Gross Amount Offset in the Statement of Financial Position	(1)	(1)
Derivative Liability, Fair Value, Net	1	4
Net Fair Value Derivative Asset offset against Collateral	4	2
Net Fair Value Derivative Liability offset against Collateral	1	4
Derivative Asset, Fair Value, Net	4	2
Commodity Contract | Derivatives designated as hedging instruments | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value	2	1
Liability Derivatives Fair Value	1	4
Commodity Contract | Derivatives not designated as hedging instruments | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value	2	1
Other Energy Management Contract [Member] | Derivatives not designated as hedging instruments | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value	5	7
Liability Derivatives Fair Value		1
Other Energy Management Contract [Member] | Derivatives not designated as hedging instruments | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	5	6
Other Energy Management Contract [Member] | Derivatives not designated as hedging instruments | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	5
Other Energy Management Contract [Member] | Derivatives not designated as hedging instruments | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Asset Derivatives Fair Value	5	6
Liability Derivatives Fair Value		6
SCEG
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	22.1	35.2
Derivative Liability, Fair Value, Net	66	75
Derivative Asset, Fair Value, Net	100	73
SCEG | Prepayments and other current assets [member]
Derivative [Line Items]
Derivative Asset, Fair Value, Net	58	42
SCEG | Other current liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Net	59	66
SCEG | Other deferred credits and other liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Net	7	9
SCEG | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Net	42	31
SCEG | Derivatives designated as hedging instruments
Derivative [Line Items]
Asset Derivatives Fair Value	100	73
Liability Derivatives Fair Value	66	75
SCEG | Interest Rate Contract
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(22)	(17)
Asset Derivatives Fair Value	100	73
Liability Derivatives Fair Value	66	75
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(22)	(17)
Collateral Already Posted, Aggregate Fair Value	22.0	35.0
Derivative Liability, Fair Value, Net	66	75
Net Fair Value Derivative Asset offset against Collateral	78	56
Net Fair Value Derivative Liability offset against Collateral	22	23
Derivative Asset, Fair Value, Net	100	73
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value	58	42
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	59	66
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	7	9
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Asset Derivatives Fair Value	$ 42	$ 31

XML

AFFILIATED TRANSACTIONS - SCEG AFFILIATED TRANSACTIONS -SCEG (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 45.2		$ 45.8
Canadys Refined Coal LLC [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage	40.00%
Cope Refined Coal LLC [Member]
Related Party Transaction [Line Items]
Related Party Transaction Purchases from Related Party	14.3	27.1
Due from Related Parties, Current	14.3	26.9
Increase (Decrease) Due from Affiliates	7.9		1.8
Equity Method Investment, Dividends or Distributions	8.0		1.8
SCEG
Related Party Transaction [Line Items]
Due to Affiliate, Current	128.0		124.0
SCEG | Canadys Refined Coal LLC [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage			10.00%
CGT [Member]
Related Party Transaction [Line Items]
Related Party Transaction Purchases from Related Party	8.4	10.0
Due to Affiliate, Current	3.2		3.4
Retail Gas Marketing and Energy Marketing
Related Party Transaction [Line Items]
Due to Affiliate, Current	14.1		13.1
Cost of Natural Gas Purchases	$ 42.1	$ 25.4

XML

RATE AND OTHER REGULATORY MATTERS (Details 3) (USD $)	3 Months Ended		12 Months Ended		24 Months Ended
	Mar. 31, 2013 MW	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2011	Jul. 31, 2012	Jan. 31, 2013	Apr. 30, 2012
Regulatory Liabilities:
MPG enviromental remediatio	28
Public Utilities, Authorized Allowable Return on Common Equity, Percentage		11.00%
Regulatory liabilities	$ 917,000,000	$ 882,000,000	$ 882,000,000
Amount allowed to be recovered through electric rates to offset incremental storm damage costs	0
Annual amount of storm damage costs which can not be offset by amounts recovered through electric rates	2.5
Accrual period of nuclear refueling charges in months	18
Regulatory Noncurrent Asset Amortization Period	30
Deferred Income Tax Charges [Member]
Regulatory Liabilities:
Regulatory liabilities	20,000,000
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities:
Regulatory liabilities	701,000,000	692,000,000	692,000,000
Storm damage reserve
Regulatory Liabilities:
Regulatory liabilities	27,000,000	27,000,000	27,000,000
Monetization bankruptcy claim [Member]
Regulatory Liabilities:
Regulatory liabilities	31,000,000	32,000,000	32,000,000
Deferred gains on interest rate derivatives
Regulatory Liabilities:
Regulatory liabilities	137,000,000	110,000,000	110,000,000
Planned major maintenance [Member]
Regulatory Liabilities:
Regulatory liabilities	1,000,000	0	0
SCEG
Regulatory Liabilities:
MPG enviromental remediatio	28
Undercollected balance fuel							80,600,000
Public Utilities Property Plant and Equipment Identifiable Capital Costs			278,000,000
Capital Cost Related to New Federal Healthcare Etc			1,000,000
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates		4.23%	2.30%	2.40%
Public Utilities, Authorized Allowable Return on Common Equity, Percentage		10.25%
historical average temperature			15
Power generation capacity six coal fired units	730
Demand Side Management Program Costs, Noncurrent	20,600,000	19,600,000	19,600,000	7,000,000		27,200,000
Regulatory liabilities	697,000,000	665,000,000	665,000,000
Amount allowed to be recovered through electric rates to offset incremental storm damage costs	100,000,000
Annual amount of storm damage costs which can not be offset by amounts recovered through electric rates	2,500,000
Accrual period of nuclear refueling charges in months	18
Regulatory Noncurrent Asset Amortization Period	30
Amounts Recovered through Electric Rates to offset Turbine Expense					18,400,000
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority		63,000,000	63,000,000
Pension Regulatory Asset Amortization Period			30
Share in Approved Capital Costs			8,000,000
Public Utilities Additional Labor Expenses for Oversight of New Units			132,000,000
SCEG | Deferred Income Tax Charges [Member]
Regulatory Liabilities:
Regulatory liabilities		$ 21,000,000	$ 21,000,000

XML

LONG-TERM AND SHORT-TERM DEBT LONG-TERM AND SHORT-TERM DEBT (Tables)

3 Months Ended

Mar. 31, 2013

Short-term Debt [Line Items]

Long-term Debt [Text Block]

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
Millions of dollars	March 31, 2013			December 31, 2012			March 31, 2013			December 31, 2012			March 31, 2013		December 31, 2012
Lines of credit:
Total committed long-term	$	300		$	300		$	1,400		$	1,400		$	100	$	100
LOC advances	—			—			—			—			—		—
Weighted average interest rate	—			—			—			—			—		—
Outstanding commercial paper (270 or fewer days)	$	122		$	142		$	408		$	449		—		$	32
Weighted average interest rate	0.48		%	0.58		%	0.33		%	0.42		%	—		0.44		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—		—
Available	$	175		$	155		$	992		$	951		$	100	$	68

SCEG

Short-term Debt [Line Items]

Long-term Debt [Text Block]

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:

Millions of dollars	March 31, 2013			December 31, 2012
Lines of credit:
Total committed long-term	$	1,400		$	1,400
LOC advances	—			—
Weighted average interest rate	—			—
Outstanding commercial paper (270 or fewer days)	$	408		$	449
Weighted average interest rate	0.33		%	0.42		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	992		$	951

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Carrying Amount
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	$ 5,211.7	$ 5,121.0
Estimated Fair Value
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	6,118.8	6,115.0
SCEG | Carrying Amount
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	3,811.0	3,722.0
SCEG | Estimated Fair Value
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	$ 4,534.8	$ 4,543.1

XML

INCOME TAXES (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	$ 2
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Other Information	38000000
SCEG
Changes to Unrecognized Tax Benefits
Balance at the end of the period	38
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	$ 38

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS CONSOLIDATED STATEMETNS OF CASH FLOWS (Paranthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Interest Paid, Capitalized	$ 2	$ 2
SCEG
Interest Paid, Capitalized	$ 2	$ 2

XML

EMPLOYEE BENEFIT PLANS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Components of Net Periodic Benefit Cost
Pension Costs Related to Retail Electric Operations and Natural Gas Operations Deferred as Regulatory Assets	$ 0.6	$ 3.7
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	5.9	4.8
Interest cost	9.5	10.7
Expected return on assets	(15.4)	(14.8)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	1.7	1.7
Defined Benefit Plan, Amortization of Transition Obligations (Assets)	0	0
Defined Benefit Plan, Actuarial Net (Gains) Losses	5.4	4.7
Defined Benefit Plan, Net Periodic Benefit Cost	7.1	7.1
Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.6	1.3
Interest cost	2.8	3.0
Expected return on assets	0	0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.2	0.2
Defined Benefit Plan, Amortization of Transition Obligations (Assets)	0.2	0.2
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.8	0.2
Defined Benefit Plan, Net Periodic Benefit Cost	5.6	4.9
SCEG
Pension and Other Postretirement Benefit Plans
Environmental Remediation Costs Recognized in Regulatory Assets	38.3
Components of Net Periodic Benefit Cost
Pension Costs Related to Retail Electric Operations and Natural Gas Operations Deferred as Regulatory Assets		3.7
SCEG | Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	4.8	3.9
Interest cost	8.0	9.1
Expected return on assets	13.0	12.6
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	1.4	1.4
Defined Benefit Plan, Actuarial Net (Gains) Losses	4.6	4.0
Defined Benefit Plan, Net Periodic Benefit Cost	5.8	5.8
SCEG | Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.2	1.0
Interest cost	2.2	2.4
Expected return on assets	0	0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.2	0.2
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.6	0.1
Defined Benefit Plan, Net Periodic Benefit Cost	$ 4.2	$ 3.7

XML

SEGMENT OF BUSINESS INFORMATION (Tables)

3 Months Ended

Mar. 31, 2013

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

industries.

Millions of dollars	External Revenue			Intersegment Revenue			Operating Income		Net Income
Three Months Ended March 31, 2013
Electric Operations	$	583		$	2		$	153	n/a
Gas Distribution	379			—			93		n/a
Retail Gas Marketing	179			—			—		$	22
Energy Marketing	167			42			—		3
All Other	12			107			7		3
Adjustments/Eliminations	(9		)	(151		)	40		123
Consolidated Total	$	1,311		—			$	293	$	151

Three Months Ended March 31, 2012
Electric Operations	$	545		$	2		$	127	n/a
Gas Distribution	274			—			83		n/a
Retail Gas Marketing	153			—			n/a		$	11
Energy Marketing	132			26			n/a		2
All Other	11			106			7		5
Adjustments/Eliminations	(8		)	(134		)	21		103
Consolidated Total	$	1,107		$	—		$	238	$	121

	March 31,		December 31,
Segment Assets	2013		2012
Electric Operations	$	9,111	$	8,989
Gas Distribution	2,308		2,292
Retail Gas Marketing	188		153
Energy Marketing	129		122
All Other	1,455		1,415
Adjustments/Eliminations	1,566		1,645
Consolidated Total	$	14,757	$	14,616

SCEG

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

.

					Earnings Available
	External		Operating		To Common
Millions of dollars	Revenue		Income		Shareholder
Three Months Ended March 31, 2013
Electric Operations	$	585	$	153	n/a
Gas Distribution	143		38		n/a
Adjustments/Eliminations	—		—		$	89
Consolidated Total	$	728	$	191	$	89

Three Months Ended March 31, 2012
Electric Operations	$	547	$	127	n/a
Gas Distribution	116		29		n/a
Adjustments/Eliminations	—		—		$	69
Consolidated Total	$	663	$	156	$	69

	March 31,		December 31,
Segment Assets	2013		2012
Electric Operations	$	9,111	$	8,989
Gas Distribution	664		659
Adjustments/Eliminations	2,503		2,456
Consolidated Total	$	12,278	$	12,104

XML

EMPLOYEE BENEFIT PLANS (Tables)

3 Months Ended

Mar. 31, 2013

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

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

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2013			2012			2013		2012
Three months ended March 31,
Service cost	$	5.9		$	4.8		$	1.6	$	1.3
Interest cost	9.5			10.7			2.8		3.0
Expected return on assets	(15.4		)	(14.8		)	—		—
Prior service cost amortization	1.7			1.7			0.2		0.2
Transition obligation amortization	—			—			0.2		0.2
Amortization of actuarial losses	5.4			4.7			0.8		0.2
Net periodic benefit cost	$	7.1		$	7.1		$	5.6	$	4.9

SCEG

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

urance 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	2013			2012			2013		2012
Three months ended March 31,
Service cost	$	4.8		$	3.9		$	1.2	$	1.0
Interest cost	8.0			9.1			2.2		2.4
Expected return on assets	(13.0		)	(12.6		)	—		—
Prior service cost amortization	1.4			1.4			0.2		0.2
Amortization of actuarial losses	4.6			4.0			0.6		0.1
Net periodic benefit cost	$	5.8		$	5.8		$	4.2	$	3.7

XML

COMMITMENTS AND CONTINGENCIES (Details) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Dec. 31, 2005
Nuclear Insurance
Inflation adjustment period for nuclear insurance	5
Environmental
Regulatory Assets, Noncurrent	$ 1,451,000,000	$ 1,464,000,000
Nuclear Generation
Estimated cash outflow for plant costs and related transmission infrastructure costs of nuclear electric generation site	6,000,000,000
SCEG
Nuclear Insurance
Federal Limit on Public Liability Claims from Nuclear Incident Approximate	12,600,000,000
Maximum Insurance Coverage for each Nuclear Plant by ANI	375,000,000
Maximum liability assessment per reactor for each nuclear incident	117,500,000	78,300,000
Maximum yearly assessment per reactor	17,500,000
Maximum prosepective insurance premium per nuclear incident	40,600,000
Maximum amount of coverage to nuclear facility for property damage and outage costs	2,750,000,000
Maximum amount of coverage for accidental property damage	500,000,000
Environmental
Number of coal fired units to be retired	6
Number of MGP decommissioned sites that contain residues of byproduct chemicals	4
Site Contingency MGP Estimated Environmental Remediation Costs	22,100,000
Deferred costs net of costs previously recovered through rates and insurance settlements included in regulatory assets	38,300,000
Regulatory Assets, Noncurrent	1,365,000,000	1,377,000,000
Nuclear Generation
Capital Cost Related to New Federal Healthcare Etc		1,000,000
Public Utilities Property Plant and Equipment Identifiable Capital Costs		278,000,000
Share in Approved Capital Costs		8,000,000
Public Utilities Additional Labor Expenses for Oversight of New Units		132,000,000
Number of states required to reduce emissions to attain mandated levels			28
Milestones for new units	146
PSNC Energy
Environmental
Number of MGP sites requiring cleanup	5
Regulatory Assets, Noncurrent	3,000,000
SCEG | SCEG
Nuclear Insurance
Maximum yearly assessment per reactor	$ 11,700,000

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Asset Management and Supply Service Agreements
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)	18.00%		44.00%
Natural gas inventory, carrying amount	$ 3.4		$ 19.6
Property, Plant and Equipment, Net	306		306
Plant to be retired coal plants	359
Earnings Per Share
Weighted Average Shares Outstanding - Basic	134.4	130.3
Incremental Common Shares Attributable to Share-based Payment Arrangements and Equity Forward Agreements	1.7	1.9
Weighted Average Number of Shares Outstanding, Diluted	136.1	132.2
SCEG
Significant Accounting Policies
Number of coal fired units to be retired	6
Asset Management and Supply Service Agreements
Property, Plant and Equipment, Net	56		57
Power generation capacity six coal fired units	730
Power Capacity of Retired Unit	90
Genco
Significant Accounting Policies
Power Generation Capacity Megawatts	605
Asset Management and Supply Service Agreements
Property, Plant and Equipment, Net	$ 472

XML

RATE AND OTHER REGULATORY MATTERS (Details) (USD $)	3 Months Ended		12 Months Ended			24 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	May 01, 2015	Dec. 31, 2012	Dec. 31, 2011	May 01, 2015	Jan. 31, 2013	Apr. 30, 2012
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	$ 1,451,000,000	$ 1,464,000,000		$ 1,464,000,000
Allowable return on common equity (as a percent)		11.00%
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates				2.10%	2.10%
Public Utilities changes in Retail Natural Gas Rates Requested and Approved under RSA				0	8.6
Basis for rate calculation		12
Regulatory Noncurrent Asset Amortization Period	30
Public Utilities Base Fuel under Collected Balance Recovery Period	12
SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	1,365,000,000	1,377,000,000		1,377,000,000
Amounts Recovered Through Electric Rates to offset Turbine Expenses	17,200,000
Share in Approved Capital Costs				8,000,000
Undercollected balance fuel								80,600,000
Number of coal fired units to be retired	6
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates		4.23%		2.30%	2.40%
Allowable return on common equity (as a percent)		10.25%
historical average temperature				15
Demand Side Management Program Costs, Noncurrent	20,600,000	19,600,000		19,600,000	7,000,000		27,200,000
Regulatory Asset Recovery Assessments			12			24
Public Utilities Property Plant and Equipment Identifiable Capital Costs				278,000,000
Capital Cost Related to New Federal Healthcare Etc				1,000,000
Public Utilities Additional Labor Expenses for Oversight of New Units				132,000,000
Increase (decrease) in retail electric rate requested under the BLRA				0	0
Basis for rate calculation	12-month rolling average
Regulatory Noncurrent Asset Amortization Period	30
Public Utilities Base Fuel under Collected Balance Recovery Period	12
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority		63,000,000		63,000,000
PSNC Energy
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	3,000,000
Deferred Pollution Control Costs
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	38,000,000	38,000,000		38,000,000
Deferred Pollution Control Costs | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	38,000,000	38,000,000		38,000,000
Franchise agreement Costs
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	34,000,000	36,000,000		36,000,000
Regulatory Noncurrent Asset Amortization Period	20
Franchise agreement Costs | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	$ 34,000,000	$ 36,000,000		$ 36,000,000
Utility Plant [Domain]
Rate Matters [Line Items]
Regulatory Noncurrent Asset Amortization Period				14

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Cash Flows From Operating Activities:
Income Available to Common Shareholders of SCANA	$ 151	$ 121
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred income taxes, net	17	50
Depreciation and amortization	97	92
Amortization of nuclear fuel	13	13
Allowance for equity funds used during construction	(4)	(3)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	(22)	65
Inventories	37	(11)
Prepayments and other	21	68
Regulatory liabilities	26	1
Accounts payable	5	(18)
Taxes accrued	(101)	(101)
Interest accrued	(6)	(1)
Regulatory assets	12	41
Changes in other assets	(16)	(43)
Changes in other liabilities	(37)	(89)
Net Cash Provided From Operating Activities	193	185
Cash Flows From Investing Activities:
Property additions and construction expenditures	(291)	(321)
Proceeds from investments (including derivative collateral posted)	100	151
Purchase of investments (including derivative collateral posted)	(84)	(109)
Payments for (Proceeds from) Hedge, Investing Activities	0	13
Payments for interest rate contract settlements	0	(51)
Net Cash Used in Investing Activities	(275)	(317)
Cash Flows From Financing Activities:
Proceeds from Issuance of Common Stock	221	26
Proceeds from issuance of long-term debt	57	494
Repayments of Long-term Debt	(66)	(259)
Dividends	(66)	(63)
Short-term borrowings, net	(93)	(68)
Net Cash Provided From Financing Activities	53	130
Net (Decrease) Increase in Cash and Cash Equivalents	(29)	(2)
Cash and Cash Equivalents, January 1	72	29
Cash and Cash Equivalents, September 30	43	27
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	77	74
Cash paid for-Income taxes	1	0
Noncash Investing and Financing Activities:
Accrued construction expenditures	88	108
Capital Lease Obligations Incurred	3	0
Noncash or Part Noncash Acquisition, Value of Assets Acquired	97	0
SCEG
Cash Flows From Operating Activities:
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	92	72
Adjustments to reconcile net income to net cash provided from operating activities:
Losses from equity method investments	1	1
Deferred income taxes, net	12	44
Depreciation and amortization	78	73
Amortization of nuclear fuel	13	13
Allowance for equity funds used during construction	(4)	(3)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	(7)	28
Inventories	10	(38)
Prepayments and other	(12)	2
Regulatory liabilities	27	1
Accounts payable	4	15
Taxes accrued	(81)	(80)
Interest accrued	(12)	(3)
Regulatory assets	11	41
Changes in other assets	(21)	(1)
Changes in other liabilities	(21)	(78)
Net Cash Provided From Operating Activities	90	87
Cash Flows From Investing Activities:
Property additions and construction expenditures	(264)	(295)
Proceeds from investments (including derivative collateral posted)	81	52
Purchase of investments (including derivative collateral posted)	(70)	(50)
Payments for (Proceeds from) Hedge, Investing Activities	0	13
Net Cash Used in Investing Activities	(253)	(280)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	57	248
Repayments of Long-term Debt	(66)	(8)
Dividends	(46)	(39)
Contributions from parent	221	24
Short-term borrowings, net	(41)	(44)
Short-term borrowings- affiliate,net	(1)	20
Net Cash Provided From Financing Activities	124	201
Net (Decrease) Increase in Cash and Cash Equivalents	(39)	8
Cash and Cash Equivalents, January 1	51	16
Cash and Cash Equivalents, September 30	12	24
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	62	51
Noncash Investing and Financing Activities:
Accrued construction expenditures	81	103
Capital Lease Obligations Incurred	1	0
Noncash or Part Noncash Acquisition, Value of Assets Acquired	$ 97	$ 0

XML

RATE AND OTHER REGULATORY MATTERS (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended	24 Months Ended
	Mar. 31, 2013	Jul. 31, 2012	Dec. 31, 2012
Regulatory Assets
MPG enviromental remediatio	28
Regulatory Noncurrent Asset, Amortization Period	30
Regulatory Assets, Noncurrent	$ 1,451.0		$ 1,464.0
SCEG
Regulatory Assets
MPG enviromental remediatio	28
Regulatory Noncurrent Asset, Amortization Period	30
Regulatory Assets, Noncurrent	1,365.0		1,377.0
Amounts Recovered through Electric Rates to offset Turbine Expense		18.4
Deferred Income Tax Charges [Member]
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	70
Regulatory Assets, Noncurrent	254.0		254.0
Deferred Income Tax Charges [Member] | SCEG
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	70
Regulatory Assets, Noncurrent	248.0		248.0
Regulatory Clause Revenues, under-recovered [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	75.0		66.0
Regulatory Clause Revenues, under-recovered [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	75.0		66.0
Environmental Restoration Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	43.0		44.0
Environmental Restoration Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	38.0		39.0
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	95
Regulatory Assets, Noncurrent	324.0		319.0
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	307.0		304.0
Franchise agreement Costs
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	20
Regulatory Assets, Noncurrent	34.0		36.0
Franchise agreement Costs | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	34.0		36.0
Pension Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	452.0		460.0
Pension Costs [Member] | SCEG
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	12
Regulatory Assets, Noncurrent	399.0		405.0
Planned major maintenance [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	0		6.0
Planned major maintenance [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	0		6.0
Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	30
Regulatory Assets, Noncurrent	141.0		151.0
Deferred Losses On Interest Rate Derivatives [Member] | SCEG
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	30
Regulatory Assets, Noncurrent	141.0		151.0
Deferred Pollution Control Costs
Regulatory Assets
Regulatory Assets, Noncurrent	38.0		38.0
Deferred Pollution Control Costs | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	38.0		38.0
unrecovered plant [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	20.0
unrecovered plant [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	20.0		20.0
Other Regulatory Assets [Member]
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	30
Regulatory Assets, Noncurrent	70.0		70.0
Other Regulatory Assets [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	$ 65.0		$ 64.0

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details 3) (USD $)	3 Months Ended					3 Months Ended			3 Months Ended						3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012	Mar. 31, 2013 Energy Management Contracts [Member]	Dec. 31, 2012 Energy Management Contracts [Member]	Mar. 31, 2013 Interest Rate Contract	Mar. 31, 2012 Interest Rate Contract	Dec. 31, 2012 Interest Rate Contract	Mar. 31, 2013 Commodity Contract	Mar. 31, 2012 Commodity Contract	Sep. 30, 2011 Commodity Contract	Mar. 31, 2013 SCEG	Mar. 31, 2012 SCEG	Dec. 31, 2012 SCEG	Mar. 31, 2013 SCEG Interest Rate Contract	Mar. 31, 2012 SCEG Interest Rate Contract	Dec. 31, 2012 SCEG Interest Rate Contract
Gain (Loss) on Derivatives
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant										insignificant	insignificant
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net						$ 35,000,000	$ 30,000,000								$ 35,000,000	$ 30,000,000
Effect of Cash Flow Hedges on Statement of Income
Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense						(1,000,000)	(1,000,000)								(1,000,000)	(1,000,000)
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	(4,000,000)	(10,000,000)				(2,000,000)	(2,000,000)		(2,000,000)	(8,000,000)
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred						6,000,000			700,000
Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense	3,000,000	(4,000,000)				1,000,000	0		(2,000,000)	4,000,000
Derivatives not designated as hedging instruments - gain (loss) recognized in income, classified in gas purchased for resale									0		(1,000,000)	0	(1,000,000)
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	60,600,000		78,300,000	(8,000,000)	(11,000,000)	(53,000,000)		(67,000,000)				22,100,000		35,200,000	22,000,000		35,000,000
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	21,300,000		26,200,000									22,200,000		22,700,000
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	81,900,000		104,500,000									44,300,000		57,900,000
Cashcollateralrequestedfromcounterparty	45,600,000		32,100,000									43,900,000		32,100,000
Derivative, net asset position	45,600,000		32,100,000									43,900,000		32,100,000
LetterofCreditAvailableCommodityDerivatives,assetposition	9,000,000		10,000,000
Commodity Derivative, net asset position	$ 9,000,000		$ 13,000,000

XML

CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Assets
Utility Plant In Service	$ 11,937	$ 11,865
Accumulated Depreciation and Amortization	(3,867)	(3,811)
Construction Work in Progress	2,250	2,084
Plant to be Retired, Net	359	362
Nuclear Fuel, Net of Accumulated Amortization	251	166
Goodwill, Net of Writedown of $230	230	230
Utility Plant, Net	11,160	10,896
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	306	306
Assets held in trust, net-nuclear decommissioning	97	94
Other investments	89	87
Nonutility Property and Investments, Net	492	487
Current Assets:
Cash and cash equivalents	43	72
Receivables, net of allowance for uncollectible accounts	775	780
Inventories (at average cost):
Fuel	250	304
Materials and supplies	140	136
Emission allowances	1	1
Prepayments and other	185	223
Deferred income taxes	10	11
Total Current Assets	1,404	1,527
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	1,451.0	1,464.0
Other	250	242
Total Deferred Debits and Other Assets	1,701	1,706
Total	14,757	14,616
Capitalization and Liabilities
Common equity	4,463	4,154
Long-Term Debt, Net	5,039	4,949
Total Capitalization	9,502	9,103
Current Liabilities:
Short-term borrowings	530	623
Current portion of long-term debt	173	172
Accounts payable	360	428
Customer deposits and customer prepayments	82	86
Taxes accrued	63	164
Interest accrued	76	82
Dividends declared	70	66
Derivative financial instruments	66	80
Other	76	110
Total Current Liabilities	1,496	1,811
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,673	1,653
Deferred investment tax credits	35	36
Asset retirement obligations	567	561
Pension and other postretirement benefits	389	387
Regulatory liabilities	917	882
Other	178	183
Total Deferred Credits and Other Liabilities	3,759	3,702
Commitments and Contingencies (Note 9)	0	0
Total	14,757	14,616
SCEG
Assets
Utility Plant In Service	10,161	10,096
Accumulated Depreciation and Amortization	(3,371)	(3,322)
Construction Work in Progress	2,227	2,073
Plant to be Retired, Net	359	362
Nuclear Fuel, Net of Accumulated Amortization	251	166
Utility Plant, Net	9,627	9,375
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	56	57
Assets held in trust, net-nuclear decommissioning	97	94
Other investments	2	3
Nonutility Property and Investments, Net	155	154
Current Assets:
Cash and cash equivalents	12	51
Receivables, net of allowance for uncollectible accounts	456	483
Due from Affiliate, Current	9	2
Inventories (at average cost):
Fuel	179	203
Materials and supplies	129	126
Emission allowances	1	1
Prepayments and other	148	143
Total Current Assets	934	1,009
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	1,365.0	1,377.0
Other	197	189
Total Deferred Debits and Other Assets	1,562	1,566
Total	12,278	12,104
Capitalization and Liabilities
Common equity	4,177	3,929
Stockholders' Equity Attributable to Noncontrolling Interest	115	114
Long-Term Debt, Net	3,646	3,557
Total Capitalization	7,938	7,600
Current Liabilities:
Short-term borrowings	408	449
Current portion of long-term debt	165	165
Accounts payable	208	281
Due to Affiliate, Current	128.0	124.0
Customer deposits and customer prepayments	53	51
Taxes accrued	70	151
Interest accrued	51	63
Dividends declared	64	46
Derivative financial instruments	59	66
Other	30	50
Total Current Liabilities	1,236	1,446
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,491	1,479
Deferred investment tax credits	35	36
Asset retirement obligations	540	535
Pension and other postretirement benefits	254	254
Regulatory liabilities	697	665
Other	87	89
Total Deferred Credits and Other Liabilities	3,104	3,058
Commitments and Contingencies (Note 9)	0	0
Total	$ 12,278	$ 12,104

XML

SEGMENT OF BUSINESS INFORMATION (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Sep. 30, 2011	Dec. 31, 2012
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	$ 583	$ 545
Intersegment Revenue	0
Operating Income	293	238
Regulated Operating Revenue, Gas	382	277
Regulated and Unregulated Operating Revenue	1,311	1,107
Income Available to Common Shareholders of SCANA	151	121
Segment Assets	14,757			14,616
Electric Operations
Segment Reporting Information [Line Items]
Intersegment Revenue	2	2
Operating Income	153	127
Segment Assets	9,111			8,989
Gas Distribution
Segment Reporting Information [Line Items]
Intersegment Revenue	0	0
Operating Income	93	83
Regulated and Unregulated Operating Revenue	379	274
Segment Assets	2,308			2,292
Retail Gas Marketing
Segment Reporting Information [Line Items]
Intersegment Revenue	0
Regulated and Unregulated Operating Revenue	179	153
Income Available to Common Shareholders of SCANA	22	11
Segment Assets	188			153
Energy Marketing
Segment Reporting Information [Line Items]
Intersegment Revenue	42	26
Regulated and Unregulated Operating Revenue	167	132
Income Available to Common Shareholders of SCANA	3	2
Segment Assets	129			122
All Other [member]
Segment Reporting Information [Line Items]
Intersegment Revenue	107	106
Operating Income	7	7
Regulated and Unregulated Operating Revenue	12	11
Income Available to Common Shareholders of SCANA	3	5
Segment Assets	1,455			1,415
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Intersegment Revenue	(151)	(134)
Operating Income	40	21
Regulated and Unregulated Operating Revenue	(9)	(8)
Income Available to Common Shareholders of SCANA	123	103
Segment Assets	1,566			1,645
SCEG
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	585	547
ERROR in label resolution.	728	663	663
Operating Income	191	156	156
Regulated Operating Revenue, Gas	143	116
Net Income (Loss) Attributable to Parent	89	69	69
Segment Assets	12,278			12,104
SCEG | Electric Operations
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	585	547
Operating Income	153	127
Segment Assets	9,111
SCEG | Gas Distribution
Segment Reporting Information [Line Items]
Operating Income	38	29
Regulated Operating Revenue, Gas	143	116
Segment Assets	664
SCEG | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Operating Income	0		0
Net Income (Loss) Attributable to Parent	89	69
Segment Assets	$ 2,503

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Net Income (Loss) Attributable to Parent [Abstract]
Income Available to Common Shareholders	$ 151		$ 121
Other Comprehensive Income (Loss)
Unrealized gains (losses) on cash flow hedging activities arising during period	3		(4)
Losses on cash flow hedging activities reclassified to net income	4		10
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax	0		0
Other Comprehensive Income	7		6
Total Comprehensive Income (Loss)	158	[1]	127	[1]
SCEG
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	92		72
Other Comprehensive Income (Loss)
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax	0		0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	92		72
Total Comprehensive Income (Loss)	92		72
Genco
Other Comprehensive Income (Loss)
Less comprehensive income attributable to noncontrolling interest	(3)		(3)
Total Comprehensive Income (Loss)	3		3
SCE&G (including Fuel Company)
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)	$ 89		$ 69

[1] Accumulated other comprehensive loss totaled $78.8 million as of March 31, 2013 and $85.6 million as of December 31, 2012.

XML

LONG-TERM AND SHORT-TERM DEBT (Details) (USD $) In Millions, unless otherwise specified														3 Months Ended		3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	May 01, 2013 SCE&G (including Fuel Company)	Mar. 31, 2013 SCE&G (including Fuel Company)	Dec. 31, 2012 SCE&G (including Fuel Company)	Oct. 15, 2012 SCE&G (including Fuel Company)	Sep. 30, 2012 SCE&G (including Fuel Company)	Mar. 31, 2013 SCEG	Dec. 31, 2012 SCEG	Sep. 30, 2012 SCEG	Mar. 31, 2013 Fuel Company	Sep. 30, 2012 Fuel Company	Jan. 31, 2013 Bonds [Member]	Mar. 31, 2013 Industrial Revenue Bonds issued by JEDA proceeds of which were loaned to subsidiary	Jan. 31, 2013 Industrial Revenue Bonds issued by JEDA proceeds of which were loaned to subsidiary	Mar. 31, 2013 Industrial and Pollution Control Bonds [Member]	Jan. 31, 2013 Industrial and Pollution Control Bonds [Member]
Debt Instrument [Line Items]
Debt Instrument, Increase, Additional Borrowings														$ 39.5		$ 14.7
Debt Instrument, Interest Rate, Stated Percentage													3.63%		4.00%		5.20%
Debt Instrument, Decrease, Repayments																56.9
Line of Credit Facility, Maximum Borrowing Capacity		1,800	200	1,400	1,400	1,400	1,200			1,200	500	500
Commercial Paper				408	449
Debt, Weighted Average Interest Rate				0.33%	0.42%
Letters of Credit Outstanding, Amount				0	0
Line of Credit Facility, Remaining Borrowing Capacity				992	951
Long-term Debt, Current Maturities	173	172						165	165
Long- Term Debt Noncurrent including Derivative Liabilities	5,039	4,949						3,646	3,557
Debt Instrument, Face Amount								$ 67.8

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

3 Months Ended

Mar. 31, 2013

Accounting Policies [Abstract]

Reconciliation of the weighted average number of common shares

Reconciliations of the weighted average number of common shares for basic and diluted earnings per share computation purposes are as follows:

Millions	2013	2012
Weighted Average Shares Outstanding - Basic	134.4	130.3
Net effect of dilutive equity forward shares	1.7	1.9
Weighted Average Shares - Diluted	136.1	132.2

XML

LONG-TERM AND SHORT-TERM DEBT (Details 2) (USD $) In Millions, unless otherwise specified	May 01, 2013	Mar. 31, 2013	Dec. 31, 2012	Oct. 15, 2012	Sep. 30, 2012
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity			$ 1,800
Number of other banks (in entities)				2
Related Party Transaction, Due from (to) Related Party, Current		48.8	49.4
Wells Fargo Bank, National Association (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	10.70%	10.70%
Bank of America, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank		10.70%
Morgan Stanly Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank		10.70%
Branch Banking and Trust Company (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank		8.90%
Credit Suisse AG, Cayman Islands Branch (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank		8.90%	8.90%
JPMorgan Chase Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank		8.90%
Mizuho Corporate Bank, Ltd (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank		8.90%
TD Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank		8.90%
UBS Loan Finance LLC (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank		8.90%
Deutsche Bank AG, New York Branch (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank		6.30%
Union Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank		6.30%
US Bank National Association (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank		6.30%
SCEG
Debt Instrument [Line Items]
Due to Affiliate, Current		128.0	124.0
Debt Instruments [Abstract]
Face value of Industrial Revenue Bonds issued, proceeds of which were availed as loan		67.8
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity					1,200
3 year credit agreement			200
Number of other banks (in entities)				2
Parent Company [Member]
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity		300	300		300
Commercial Paper		122	142
Commercial paper, weighted average interest rate (as a percent)		0.4818%	0.58%
Letters of credit supported by LOC		3.0	3.0
Line of Credit Facility, Remaining Borrowing Capacity		175	155
LOC advances		0	0
Retail Gas Marketing and Energy Marketing
Debt Instrument [Line Items]
Due to Affiliate, Current		14.1	13.1
SCE&G (including Fuel Company)
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity	200	1,400	1,400	1,400	1,200
Commercial Paper		408	449
Commercial paper, weighted average interest rate (as a percent)		0.33%	0.42%
Letters of credit supported by LOC		0	0
Line of Credit Facility, Remaining Borrowing Capacity		992	951
LOC advances		0	0
SCE&G (including Fuel Company) | Wells Fargo Bank, National Association (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank			10.70%
SCE&G (including Fuel Company) | Branch Banking and Trust Company (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank			6.30%
SCE&G (including Fuel Company) | Credit Suisse AG, Cayman Islands Branch (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank			8.90%
SCE and G [Member] | Deutsche Bank AG, New York Branch (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	6.30%
Fuel Company
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity		500			500
PSNC Energy
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity			100		100
Commercial Paper		0	32
Commercial paper, weighted average interest rate (as a percent)		0.00%	0.44%
Letters of credit supported by LOC		0	0
Line of Credit Facility, Remaining Borrowing Capacity		100	68
LOC advances		$ 0	$ 0

XML

COMMON EQUITY (Tables)

3 Months Ended

Mar. 31, 2013

Schedule of Capitalization, Equity [Line Items]

Reclassifications from Other Comprehensive Income [Table Text Block]

Reclassifications of gains (losses) from AOCI into earnings were as follows:

	Three Months Ended March 31,						Income Statement
Millions of dollars	2013			2012			Line Item Affected
Interest rate contracts	$	(2	)	$	(2	)	Increase in interest expense
Commodity contracts	(2		)	(8		)	Increase in gas purchased for resale
Amortization of deferred employee benefit plan costs	—			—
Total reclassifications	$	(4	)	$	(10	)

Reclassifications of the amortization of deferred employee benefit costs were not significant for any period presented.

Schedule of Stockholders Equity [Table Text Block]

Changes in common equity during the three months ended March 31, 2013 and 2012 were as follows:

Millions of dollars	2013			2012
Balance at January 1,	$	4,154		$	3,889
Common stock issued	221			26
Dividends declared	(70		)	(65		)
Comprehensive income	158			127
Balance as of March 31,	$	4,463		$	3,977

SCEG

Schedule of Capitalization, Equity [Line Items]

Schedule of Stockholders Equity [Table Text Block]

Changes in common equity during the three months ended March 31, 2013 and 2012 were as follows:

Millions of dollars	Common Equity			Noncontrolling Interest			Total Equity
Balance at January 1, 2013	$	3,929		$	114		$	4,043
Capital contribution from parent	221			—			221
Dividends declared	(62		)	(2		)	(64		)
Comprehensive income	89			3			92
Balance as of March 31, 2013	$	4,177		$	115		$	4,292
Balance at January 1, 2012	$	3,665		$	108		$	3,773
Capital contribution from parent	24			—			24
Dividends declared	(51		)	(2		)	(53		)
Comprehensive income	69			3			72
Balance as of March 31, 2012	$	3,707		$	109		$	3,816

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME PARENTHETICAL STATEMENTS OF COMPREHENSIVE INCOME (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ 78.8		$ 85.6
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	2,000,000	(2,000,000)
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax	2,000,000	6,000,000
SCEG
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ 3,900,000		$ 4,000,000

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Public Utilities, Property, Plant and Equipment, Net	$ 11,160	$ 10,896
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	142	139
Allowance for Doubtful Accounts Receivable, Current	7	7
Assets, Current	1,404	1,527
Regulated Entity, Other Assets, Noncurrent	1,701	1,706
SCEG
Public Utilities, Property, Plant and Equipment, Net	9,627	9,375
Allowance for Doubtful Accounts Receivable, Current	3	3
Assets, Current	934	1,009
Regulated Entity, Other Assets, Noncurrent	1,562	1,566
SCEG | Variable Interest Entity, Primary Beneficiary [Member]
Public Utilities, Property, Plant and Equipment, Net	626	640
Assets, Current	184	206
Regulated Entity, Other Assets, Noncurrent	$ 58	$ 54

XML

EMPLOYEE BENEFIT PLANS

3 Months Ended

Mar. 31, 2013

Pension and Other Postretirement Benefit Plans

EMPLOYEE BENEFIT PLANS

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	2013			2012			2013		2012
Three months ended March 31,
Service cost	$	5.9		$	4.8		$	1.6	$	1.3
Interest cost	9.5			10.7			2.8		3.0
Expected return on assets	(15.4		)	(14.8		)	—		—
Prior service cost amortization	1.7			1.7			0.2		0.2
Transition obligation amortization	—			—			0.2		0.2
Amortization of actuarial losses	5.4			4.7			0.8		0.2
Net periodic benefit cost	$	7.1		$	7.1		$	5.6	$	4.9

No contribution to the pension trust will be necessary until after 2014, nor will limitations on benefit payments apply.   In connection with the SCPSC's December 2012 rate order, effective January 1, 2013 SCE&G began recovering pension expense related to retail electric operations through a rate rider that is adjusted annually. As authorized by the SCPSC, prior to January 1, 2013 SCE&G deferred all pension expense related to retail electric operations as a regulatory asset, and has deferred such costs related to gas operations during both periods presented. Costs totaling $0.6 million and $3.7 million were deferred for the three months ended March 31, 2013 and 2012, respectively. Previously deferred costs related to electric operations are being recovered as described in Note 2.

SCEG

Pension and Other Postretirement Benefit Plans

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	2013			2012			2013		2012
Three months ended March 31,
Service cost	$	4.8		$	3.9		$	1.2	$	1.0
Interest cost	8.0			9.1			2.2		2.4
Expected return on assets	(13.0		)	(12.6		)	—		—
Prior service cost amortization	1.4			1.4			0.2		0.2
Amortization of actuarial losses	4.6			4.0			0.6		0.1
Net periodic benefit cost	$	5.8		$	5.8		$	4.2	$	3.7

No contribution to the pension trust will be necessary until after 2014, nor will limitations on benefit payments apply.  In connection with the SCPSC's December 2012 rate order, effective January 1, 2013 SCE&G began recovering pension expense related to retail electric operations through a rate rider that is adjusted annually. As authorized by the SCPSC, prior to January 1, 2013 SCE&G deferred all pension expense related to retail electric operations as a regulatory asset, and has deferred such costs related to gas operations during both periods presented. Costs totaling $0.6 million and $3.7 million were deferred for the three months ended March 31, 2013 and 2012, respectively. Previously deferred cost related to electric operations are being recovered as described in Note 2.

XML

Document and Entity Information Document	3 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2013	Apr. 30, 2013
Entity Information [Line Items]
Entity Registrant Name	SCANA Corporation
Entity Central Index Key	0000754737
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2013
Document Fiscal Year Focus		2013
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding			139,498,499
SCEG
Entity Information [Line Items]
Entity Registrant Name	SOUTH CAROLINA ELECTRIC & GAS CO
Entity Central Index Key	0000091882
Current Fiscal Year End Date		--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2013
Document Fiscal Year Focus		2013
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding			40,296,147

XML

COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 2013

Statement [Line Items]

Commitments and Contingencies Disclosure [Text Block]

9. COMMITMENTS AND CONTINGENCIES

Nuclear Insurance

Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the Company's nuclear power plant. Price-Anderson provides funds up to $12.6 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. 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 Unit 1, would be $78.3 million per incident, but not more than $11.7 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper) with NEIL.  The policies provide coverage to Summer Station Unit 1 for property damage and outage costs up to $2.75 billion. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million in limits of accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies 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 $40.6 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power or other costs and expenses, 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 impact on the Company’s results of operations, cash flows and financial position.

Environmental

On April 13, 2012, the EPA issued a proposed rule to establish NSPS for GHG emissions from fossil fuel-fired electric generating units. If finalized as proposed, this rule would establish performance standards for new and modified generating units, along with emissions guidelines for existing generating units. This rule would amend the NSPS for electric generating units and establish the first NSPS for GHG emissions. Essentially, the rule would require all new fossil fuel-fired power plants to meet the carbon dioxide emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal plants could be constructed without carbon capture and sequestration capabilities. The Company is evaluating the proposed rule, but cannot predict when the rule will become final, if at all, or what conditions it may impose on the Company, if any. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

In 2005, the EPA issued the CAIR, which 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.  On July 6, 2011 the EPA issued the CSAPR.  This rule replaced 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.  CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. On August 21, 2012, the Court of Appeals vacated CSAPR and left CAIR in place. The EPA's petition for rehearing of the Court of Appeals' order has been denied. On March 29, 2013, the U.S. Solicitor General petitioned the U.S. Supreme Court to review the D.C. Circuit Court's decision on CSAPR. Air quality control installations that SCE&G and GENCO have already completed allowed the Company to comply with the reinstated CAIR.  The Company will continue to pursue strategies to comply with all applicable environmental regulations.  Any costs incurred to comply with such regulations are expected to be recoverable through rates.

In April 2012, the EPA's rule containing new standards for mercury and other specified air pollutants became effective.  The rule provides up to four years for facilities to meet the standards, and the Company's evaluation of the rule is ongoing. The Company's decision in 2012 to retire certain coal-fired units or convert them to burn natural gas and its project to build the New Units (see Note 1) along with other actions are expected to result in the Company's compliance with the EPA's rule.  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.

The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the NSPS of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement. Though the Company cannot predict what action, if any, the EPA will initiate against it, any costs incurred are expected to be recoverable through rates.

The Company 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.  Environmental liabilities are accrued when the criteria for loss contingencies are met. 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.  Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are recorded to expense.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of byproduct chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA.  SCE&G anticipates that major remediation activities at all these sites will continue until 2016 and will cost an additional $22.1 million, which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.  At March 31, 2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $38.3 million and are included in regulatory assets.

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 approximately $3.0 million, the estimated remaining liability at March 31, 2013. PSNC Energy expects to recover through rates any cost allocable to PSNC Energy arising from the remediation of these sites.

New Nuclear Construction

SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $6.0 billion for plant costs and for related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC. There are 146 milestones for purposes of reporting the construction schedule of the New Units to the SCPSC.  The delayed schedule for the fabrication and delivery of sub-modules is a focus area of the construction of the New Units.  SCE&G is devoting resources to monitor this focus area, including mitigation options, due to the potential to affect the construction schedule. The first New Unit is scheduled for substantial completion in 2017, and the second in 2018.

The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude.  During the course of activities under the EPC Contract, issues have materialized that impact project budget and schedule. Claims specifically relating to COL delays,

design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock

conditions at the site resulted in assertions of contractual entitlement to recover additional costs to be incurred. The resolution

of these specific claims is discussed in Note 2. SCE&G expects to resolve any disputes that arise in the future through both the

informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as

well as other costs identified from time to time, will be recoverable through rates.

When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units.  In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation, as well as a request for information related to emergency plant staffing.  These conditions and requirements are responsive to the NRC's Near-Term Task Force report titled “Recommendations for Enhancing Reactor Safety in the 21st Century.”  This report was prepared in the wake of the March 2011 earthquake-generated tsunami, which severely damaged several nuclear generating units and their back-up cooling systems in Japan.  SCE&G continues to evaluate the impact these conditions and requirements impose on the construction and operation of the New Units, and SCE&G is preparing an integrated response plan to submit to the NRC for the New Units.  SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New 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. 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.

SCEG

Statement [Line Items]

Commitments and Contingencies Disclosure [Text Block]

COMMITMENTS AND CONTINGENCIES

 Nuclear Insurance

Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the Company's nuclear power plant. Price-Anderson provides funds up to $12.6 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. 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 Unit 1, would be $78.3 million per incident, but not more than $11.7 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper) with NEIL.  The policies provide coverage to Summer Station Unit 1 for property damage and outage costs up to $2.75 billion. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million in limits of accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies 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 $40.6 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power or other cost and expenses, 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 impact on the Company’s results of operations, cash flows and financial position.

Environmental

On April 13, 2012, the EPA issued a proposed rule to establish NSPS for GHG emissions from fossil fuel-fired electric generating units. If finalized as proposed, this rule would establish performance standards for new and modified generating units, along with emissions guidelines for existing generating units. This rule would amend the NSPS for electric generating units and establish the first NSPS for GHG emissions. Essentially, the rule would require all new fossil fuel-fired power plants to meet the carbon dioxide emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal plants could be constructed without carbon capture and sequestration capabilities. Consolidated SCE&G is evaluating the proposed rule, but cannot predict when the rule will become final, if at all, or what conditions it may impose on Consolidated SCE&G, if any.  Consolidated SCE&G expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

In 2005, the EPA issued the CAIR, which 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. On July 6, 2011 the EPA issued the CSAPR.  This rule replaced 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.  CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. On August 21, 2012, the Court of Appeals vacated CSAPR and left CAIR in place. The EPA's petition for rehearing of the Court of Appeals' order has been denied. On March 29, 2013, the U.S. Solicitor General petitioned the U. S. Supreme Court to review the D.C. Circuit Court's decision on CSAPR. Air quality control installations that SCE&G and GENCO have already completed allowed Consolidated SCE&G to comply with the reinstated CAIR.  Consolidated SCE&G will continue to pursue strategies to comply with all applicable environmental regulations.  Any costs incurred to comply with such regulations are expected to be recoverable through rates.

In April 2012, the EPA's rule containing new standards for mercury and other specified air pollutants became effective.  The rule provides up to four years for facilities to meet the standards, and Consolidated SCE&G's evaluation of the rule is ongoing. Consolidated SCE&G's decision in 2012 to retire certain coal-fired units or convert them to burn natural gas and its project to build the New Units (see Note 1) along with other actions are expected to result in Consolidated SCE&G's compliance with the EPA's rule.  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.

The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the NSPS of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement. Though Consolidated SCE&G cannot predict what action, if any, the EPA will initiate against it, any costs incurred are expected to be recoverable through rates.

Consolidated 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.  Environmental liabilities are accrued when the criteria for loss contingencies are met. 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.  Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are recorded to expense.

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 and the EPA.  SCE&G anticipates that major remediation activities at all these sites will continue until 2016 and will cost an additional $22.1 million, which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.  At March 31, 2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $38.3 million and are included in regulatory assets.

New Nuclear Construction

SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $6.0 billion for plant costs and for related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC. There are 146 milestones for purposes of reporting the construction schedule of the New Units to the SCPSC.  The delayed schedule for the fabrication and delivery of sub-modules is a focus area of the construction of the New Units.  SCE&G is devoting resources to monitor this focus area, including mitigation options, due to the potential to affect the construction schedule. The first New Unit is scheduled for substantial completion in 2017, and the second in 2018.

The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude.  During the course of activities under the EPC Contract, issues have materialized that impact project budget and schedule. Claims specifically relating to COL delays,

design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock

conditions at the site resulted in assertions of contractual entitlement to recover additional costs to be incurred. The resolution

of these specific claims is discussed in Note 2. SCE&G expects to resolve any disputes that arise in the future through both the

informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as

well as other costs identified from time to time, will be recoverable through rates.

When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units.  In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation, as well as a request for information related to emergency plant staffing.  These conditions and requirements are responsive to the NRC's Near-Term Task Force report titled “Recommendations for Enhancing Reactor Safety in the 21st Century.”  This report was prepared in the wake of the March 2011 earthquake-generated tsunami, which severely damaged several nuclear generating units and their back-up cooling systems in Japan.  SCE&G continues to evaluate the impact these conditions and requirements impose on the construction and operation of the New Units, and SCE&G is preparing an integrated response plan to submit to the NRC for the New Units.  SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New 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. 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.

XML

CONSOLIDATED STATEMENTS OF INCOME (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Operating Revenues:
Electric Domestic Regulated Revenue	$ 583	$ 545
Regulated Operating Revenue, Gas	382	277
Gas-nonregulated	346	285
Regulated and Unregulated Operating Revenue	1,311	1,107
Operating Expenses [Abstract]
Fuel used in electric generation	186	181
Purchased power	7	6
Gas purchased for resale	501	366
Other operation and maintenance	176	175
Depreciation and amortization	93	89
Other taxes	55	52
Total Operating Expenses	1,018	869
Operating Income	293	238
Other Income (Expense):
Interest Expense	(75)	(72)
Other income	13	14
Other expenses	(12)	(10)
Allowance for equity funds used during construction	4	3
Total Other Expense	(70)	(65)
Income Before Income Tax Expense	223	173
Income Tax Expense	72	52
Income Available to Common Shareholders	151	121
Per Common Share Data
Basic Earnings Per Share of Common Stock (in dollars per share)	$ 1.13	$ 0.93
Diluted Earnings Per Share of Common Stock (in dollars per share)	$ 1.11	$ 0.91
Weighted Average Common Shares Outstanding (millions)
Weighted Average Number of Shares Outstanding, Basic	134.4	130.3
Weighted Average Number of Shares Outstanding, Diluted	136.1	132.2
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 0.5075	$ 0.495
SCEG
Operating Revenues:
Electric Domestic Regulated Revenue	585	547
Regulated Operating Revenue, Gas	143	116
Total Operating Revenues	728	663
Operating Expenses [Abstract]
Fuel used in electric generation	188	183
Purchased power	7	6
Gas purchased for resale	77	59
Other operation and maintenance	138	138
Depreciation and amortization	77	73
Other taxes	50	48
Total Operating Expenses	537	507
Operating Income	191	156
Other Income (Expense):
Interest Expense	(55)	(51)
Other expenses	(4)	(4)
Allowance for equity funds used during construction	4	3
Total Other Expense	(55)	(52)
Income Before Income Tax Expense	136	104
Income Tax Expense	44	32
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	92	72
Net Income (Loss) Attributable to Noncontrolling Interest	(3)	(3)
Net Income (Loss) Attributable to Parent	89	69
Weighted Average Common Shares Outstanding (millions)
Dividends, Common Stock, Cash	$ 64	$ 53

XML

COMMON EQUITY

3 Months Ended

Mar. 31, 2013

Stockholders' Equity Note [Abstract]

COMMON EQUITY

COMMON EQUITY

Changes in common equity during the three months ended March 31, 2013 and 2012 were as follows:

Millions of dollars	2013			2012
Balance at January 1,	$	4,154		$	3,889
Common stock issued	221			26
Dividends declared	(70		)	(65		)
Comprehensive income	158			127
Balance as of March 31,	$	4,463		$	3,977

SCANA had 200 million shares of common stock authorized as of March 31, 2013 and December 31, 2012, of which 139.2 million and 132.0 million were issued and outstanding at March 31, 2013 and December 31, 2012, respectively.

On March 5, 2013, SCANA settled all forward sales contracts related to its common stock through the issuance of approximately 6.6 million common shares, resulting in net proceeds of approximately $196.2 million.

Reclassifications of gains (losses) from AOCI into earnings were as follows:

	Three Months Ended March 31,						Income Statement
Millions of dollars	2013			2012			Line Item Affected
Interest rate contracts	$	(2	)	$	(2	)	Increase in interest expense
Commodity contracts	(2		)	(8		)	Increase in gas purchased for resale
Amortization of deferred employee benefit plan costs	—			—
Total reclassifications	$	(4	)	$	(10	)

Reclassifications of the amortization of deferred employee benefit costs were not significant for any period presented.

SCEG

Stockholders' Equity Note [Abstract]

COMMON EQUITY

EQUITY

Changes in common equity during the three months ended March 31, 2013 and 2012 were as follows:

Millions of dollars	Common Equity			Noncontrolling Interest			Total Equity
Balance at January 1, 2013	$	3,929		$	114		$	4,043
Capital contribution from parent	221			—			221
Dividends declared	(62		)	(2		)	(64		)
Comprehensive income	89			3			92
Balance as of March 31, 2013	$	4,177		$	115		$	4,292
Balance at January 1, 2012	$	3,665		$	108		$	3,773
Capital contribution from parent	24			—			24
Dividends declared	(51		)	(2		)	(53		)
Comprehensive income	69			3			72
Balance as of March 31, 2012	$	3,707		$	109		$	3,816

SCE&G had 50 million shares of common stock authorized as of March 31, 2013 and December 31, 2012, of which 40.3 million were issued and outstanding during all periods presented. SCE&G had 20 million shares of preferred stock authorized as of March 31, 2013 and December 31, 2012, of which 1,000 shares were issued and outstanding during all periods presented. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA.

Reclassifications from AOCI into earnings of the amortization of deferred employee benefit costs were not significant for any period presented.

XML

RATE AND OTHER REGULATORY MATTERS

3 Months Ended

Mar. 31, 2013

Rate Matters [Line Items]

Public Utilities Disclosure [Text Block]

RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G's retail electric rates include 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. In April 2012, the SCPSC approved SCE&G's request to decrease the total fuel cost component of its retail electric rates, and approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to recover an amount equal to its actual under-collected balance of base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a 12-month period beginning with the first billing cycle of May 2012.

In the December 2012 rate order, the SCPSC authorized SCE&G to reduce the base fuel cost component of its retail electric rates and in doing so, stated that SCE&G may not adjust its base fuel component prior to April 1, 2014, except where necessary due to extraordinary unforeseen economic or financial conditions.  In February 2013, in connection with its annual review of base rates for fuel costs, SCE&G requested authorization to reduce its environmental fuel cost component effective with the first billing cycle of May 2013.  Consistent with the December 2012 rate order, however, SCE&G did not request any adjustment to its base fuel cost component.  On March 14, 2013 SCE&G, ORS and the SCEUC entered into a settlement agreement accepting the proposed lower environmental fuel cost component effective the first billing cycle of May 2013.  By not adjusting SCE&G's base fuel component, the settlement also provided for carrying costs on a portion of the undercollected balance of fuel costs.  The SCPSC approved this settlement agreement on April 10, 2013.

On December 19, 2012, the SCPSC approved a 4.23% overall increase in SCE&G's retail electric base rates, effective January 1, 2013, and authorized an allowed return on common equity of 10.25%. The SCPSC also approved a mid-period reduction to the cost of fuel component in rates, a reduction in the DSM Programs component rider to retail rates, and the recovery of and a return on the net carrying value of certain retired generating plant assets described below. By order dated February 7, 2013, the SCPSC denied the SCEUC's petition for rehearing of this order.

The eWNA is designed to reduce volatility of costs charged to residential and commercial customers due to abnormal weather and is based on a 15 year historical average of temperatures. In connection with the December 2012 rate order, SCE&G agreed to perform a study of alternative structures for eWNA by June 30, 2013, which may be used to modify or terminate eWNA in the future.

In February 2013, SCE&G filed an IRP with the SCPSC. The IRP evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. The IRP identified a total of six coal-fired units that SCE&G intends to retire by 2018, subject to future developments in environmental regulations, among other matters. The net carrying value of a unit that has been retired is recorded in regulatory assets as unrecovered plant and is being amortized over its original remaining useful life as further described below. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.

SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and lost net margin revenue associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G submits annual filings in January to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC has approved the following rate changes pursuant to annual DSM Programs filings, which changes went into effect as indicated below:

Year	Effective	Amount
2012	First billing cycle of May	$19.6 million
2011	First billing cycle of June	$7.0 million

In January 2013, SCE&G filed its annual update on DSM Programs and a petition for an update to the rate rider requesting an increase of approximately $27.2 million. On April 1, 2013, ORS filed a report of its review of SCE&G's DSM Programs petition with the SCPSC. ORS proposed that SCE&G recover the net lost revenue component of the rider of $20.6 million over a 24-month period effective for bills rendered on and after the first billing cycle in May 2013. ORS also recommended that SCE&G defer a portion of net lost revenue component in a regulatory asset and recover those amounts over a 12-month period effective for bills rendered on and after the first billing cycle in May 2014. SCE&G agreed with ORS's recommendations. In April 2013, the SCPSC approved SCE&G's request to update its rider as modified by the agreement between ORS and SCE&G.

Electric – BLRA

In November 2012, the SCPSC approved an updated construction schedule and additional updated capital costs of $278 million (SCE&G's portion in 2007 dollars). The November 2012 order approved additional identifiable capital costs of approximately $1 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications; approximately $8 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure; and approximately $132 million (SCE&G's portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. In addition, the order approved revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims for costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals.

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 11.0%. The SCPSC has approved the following rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated:

Year	Action			Amount
2012	2.3	%	Increase	$52.1 million
2011	2.4	%	Increase	$52.8 million

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. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the years indicated:

Year	Action			Amount
2012	2.1	%	Increase	$7.5 million
2011	2.1	%	Increase	$8.6 million

SCE&G's natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. SCE&G's gas rates are calculated using a methodology which may adjust 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 held in November 2012 before the SCPSC. The SCPSC issued an order in December 2012 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2011 through July 31, 2012, were reasonable and prudent.

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 periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collection of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In 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 2012, in connection with PSNC Energy's 2012 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, 2012.

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 regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.

Millions of dollars	March 31, 2013		December 31, 2012
Regulatory Assets:
Accumulated deferred income taxes	$	254	$	254
Under-collections - electric fuel adjustment clause	75		66
Environmental remediation costs	43		44
AROs and related funding	324		319
Franchise agreements	34		36
Deferred employee benefit plan costs	452		460
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	141		151
Deferred pollution control costs	38		38
Unrecovered plant	20		20
Other	70		70
Total Regulatory Assets	$	1,451	$	1,464

Regulatory Liabilities:
Accumulated deferred income taxes	$	20	$	21
Asset removal costs	701		692
Storm damage reserve	27		27
Monetization of bankruptcy claim	31		32
Deferred gains on interest rate derivatives	137		110
Planned major maintenance	1		—
Total Regulatory Liabilities	$	917	$	882

Accumulated deferred income tax liabilities that arose from utility operations that have not been included in customer rates are recorded as a regulatory asset.  Substantially all of these regulatory assets relate to depreciation and 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 not expected to be recovered in retail electric rates within 12 months. 

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 28 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. In connection with the December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are to be recovered through utility rates over approximately 30 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 12 years.

Planned major maintenance related to certain fossil fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders.  SCE&G collects $18.4 million annually for fossil fueled turbine/generation equipment maintenance.  Through December 31, 2012, nuclear refueling charges were accrued during each 18-month refueling outage cycle as a component of cost of service. In connection with the December 2012 rate order, effective January 1, 2013, SCE&G began to collect and accrue $17.2 million annually for nuclear-related refueling charges.

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.

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at Wateree and Williams Stations pursuant to specific regulatory orders.  Such costs will be recovered through utility rates over periods up to 30 years. 

Unrecovered plant represents the net book value of a coal-fired generating unit retired from service prior to being fully depreciated. Pursuant to the December 2012 rate order, SCE&G is amortizing these amounts over the unit's original remaining useful life of approximately 14 years. Unamortized amounts are included in rate base.

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. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely.

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

The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been approved for recovery by the SCPSC, the NCUC or by the FERC. In recording such 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. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. 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 effect on the Company's results of operations, liquidity or financial position in the period the write-off would be recorded.

SCEG

Rate Matters [Line Items]

Public Utilities Disclosure [Text Block]

RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G's retail electric rates include 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. In April 2012, the SCPSC approved SCE&G's request to decrease the total fuel cost component of its retail electric rates, and approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to recover an amount equal to its actual under-collected balance of base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a 12-month period beginning with the first billing cycle of May 2012.

In the December 2012 rate order, the SCPSC authorized SCE&G to reduce the base fuel cost component of its retail electric rates and in doing so, stated that SCE&G may not adjust its base fuel component prior to April 1, 2014, except where necessary due to extraordinary unforeseen economic or financial conditions.  In February 2013, in connection with its annual review of base rates for fuel costs, SCE&G requested authorization to reduce its environmental fuel cost component effective with the first billing cycle of May 2013.  Consistent with the December 2012 rate order, however, SCE&G did not request any adjustment to its base fuel cost component.  On March 14, 2013 SCE&G, ORS and the SCEUC entered into a settlement agreement accepting the proposed lower environmental fuel cost component effective the first billing cycle of May 2013.  By not adjusting SCE&G's base fuel component, the settlement also provided for carrying costs on a portion of the undercollected balance of fuel costs.  The SCPSC approved this settlement agreement on April 10, 2013.

On December 19, 2012, the SCPSC approved a 4.23% overall increase in SCE&G's retail electric base rates, effective January 1, 2013, and authorized an allowed return on common equity of 10.25%. The SCPSC also approved a mid-period reduction to the cost of fuel component in rates, a reduction in the DSM Programs component rider to retail rates, and the recovery of and a return on the net carrying value of certain retired generating plant assets described below. By order dated February 7, 2013, the SCPSC denied the SCEUC's petition for rehearing of this order.

The eWNA is designed to reduce volatility of costs charged to residential and commercial customers due to abnormal weather and is based on a 15 year historical average of temperatures. In connection with the December 2012 rate order, SCE&G agreed to perform a study of alternative structures for eWNA by June 30, 2013, which may be used to modify or terminate eWNA in the future.

In February 2013, SCE&G filed an IRP with the SCPSC. The IRP evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. The IRP identified a total of six coal-fired units that SCE&G intends to retire by 2018, subject to future developments in environmental regulations, among other matters. The net carrying value of a unit that has been retired is recorded in regulatory assets as unrecovered plant and is being amortized over its original remaining useful life as further described below. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.

SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and lost net margin revenue associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G submits annual filings in January to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC has approved the following rate changes pursuant to annual DSM Programs filings, which changes went into effect as indicated below:

Year	Effective	Amount
2012	First billing cycle of May	$19.6 million
2011	First billing cycle of June	$7.0 million

In January 2013, SCE&G filed its annual update on DSM Programs and a petition for an update to the rate rider, requesting an increase of approximately $27.2 million. On April 1, 2013, ORS filed a report of its review of SCE&G's DSM Programs petition with the SCPSC. ORS proposed that SCE&G recover the net lost revenue component of the rider of $20.6 million over a 24-month period effective for bills rendered on and after the first billing cycle in May 2013. ORS also recommended that SCE&G defer a portion of net lost revenue component in a regulatory asset and recover those amounts over a 12-month period effective for bills rendered on and after the first billing cycle in May 2014. SCE&G agreed with ORS's recommendations. In April 2013, the SCPSC approved SCE&G's request to update its rider as modified by the agreement between ORS and SCE&G.

Electric – BLRA

In November 2012, the SCPSC approved an updated construction schedule and additional updated capital costs of $278 million (SCE&G's portion in 2007 dollars). The November 2012 order approved additional identifiable capital costs of approximately $1 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications; approximately $8 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure; and approximately $132 million (SCE&G's portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. In addition, the order approved revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims for costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals.

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 11.0%. The SCPSC has approved the following rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated:

Year	Action			Amount
2012	2.3	%	Increase	$52.1 million
2011	2.4	%	Increase	$52.8 million

Gas

The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the years indicated:

Year	Action			Amount
2012	2.1	%	Increase	$7.5 million
2011	2.1	%	Increase	$8.6 million

SCE&G's natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. SCE&G's gas rates are calculated using a methodology which may adjust 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 held in November 2012 before the SCPSC. The SCPSC issued an order in December 2012 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2011 through July 31, 2012, were reasonable and prudent.

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 regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.  

Millions of dollars	March 31, 2013		December 31, 2012
Regulatory Assets:
Accumulated deferred income taxes	$	248	$	248
Under collections – electric fuel adjustment clause	75		66
Environmental remediation costs	38		39
AROs and related funding	307		304
Franchise agreements	34		36
Deferred employee benefit plan costs	399		405
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	141		151
Deferred pollution control costs	38		38
Unrecovered plant	20		20
Other	65		64
Total Regulatory Assets	$	1,365	$	1,377

Regulatory Liabilities:
Accumulated deferred income taxes	$	20	$	21
Asset removal costs	512		507
Storm damage reserve	27		27
Deferred gains on interest rate derivatives	137		110
Planned major maintenance	1		—
Total Regulatory Liabilities	$	697	$	665

Accumulated deferred income tax liabilities that arose from utility operations that have not been included in customer rates are recorded as a regulatory asset.  Substantially all of these regulatory assets relate to depreciation and 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 not expected to be recovered in retail electric rates within 12 months. 

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 periods of up to approximately 28 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. In connection with the December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are to be recovered through utility rates over approximately 30 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 12 years.

Planned major maintenance related to certain fossil fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders.  SCE&G collects $18.4 million annually for fossil fueled turbine/generation equipment maintenance.  Through December 31, 2012, nuclear refueling charges were accrued during each 18-month refueling outage cycle as a component of cost of service. In connection with the December 2012 rate order, effective January 1, 2013, SCE&G began to collect and accrue $17.2 million annually for nuclear-related refueling charges.

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.

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at Wateree and Williams Stations pursuant to specific regulatory orders.  Such costs will be recovered through utility rates over periods up to 30years. 

Unrecovered plant represents the net book value of a coal-fired generating unit retired from service prior to being fully depreciated. Pursuant to the December 2012 rate order, SCE&G is amortizing these amounts over the unit's original remaining useful life of approximately 14 years. Unamortized amounts are included in rate base.

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. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely.

The SCPSC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been approved for recovery by the SCPSC or by the FERC. In recording such 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. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. 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 effect on Consolidated SCE&G's results of operations, liquidity or financial position in the period the write-off would be recorded.

XML

RATE AND OTHER REGULATORY MATTERS (Tables)

3 Months Ended

Mar. 31, 2013

Regulatory Assets

Demand reduction programs [Table Text Block]

Year	Effective	Amount
2012	First billing cycle of May	$19.6 million
2011	First billing cycle of June	$7.0 million

Schedule of Regulatory Assets [Table Text Block]

Millions of dollars	March 31, 2013		December 31, 2012
Regulatory Assets:
Accumulated deferred income taxes	$	254	$	254
Under-collections - electric fuel adjustment clause	75		66
Environmental remediation costs	43		44
AROs and related funding	324		319
Franchise agreements	34		36
Deferred employee benefit plan costs	452		460
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	141		151
Deferred pollution control costs	38		38
Unrecovered plant	20		20
Other	70		70
Total Regulatory Assets	$	1,451	$	1,464

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Accumulated deferred income taxes	$	20	$	21
Asset removal costs	701		692
Storm damage reserve	27		27
Monetization of bankruptcy claim	31		32
Deferred gains on interest rate derivatives	137		110
Planned major maintenance	1		—
Total Regulatory Liabilities	$	917	$	882

Schedule of Changes in Electric Rate BLRA [Table Text Block]

Year	Action			Amount
2012	2.3	%	Increase	$52.1 million
2011	2.4	%	Increase	$52.8 million

Schedule of Changes in Gas Rate RSA [Table Text Block]

Year	Action			Amount
2012	2.1	%	Increase	$7.5 million
2011	2.1	%	Increase	$8.6 million

SCEG

Regulatory Assets

Demand reduction programs [Table Text Block]

Year	Effective	Amount
2012	First billing cycle of May	$19.6 million
2011	First billing cycle of June	$7.0 million

Schedule of Regulatory Assets [Table Text Block]

Millions of dollars	March 31, 2013		December 31, 2012
Regulatory Assets:
Accumulated deferred income taxes	$	248	$	248
Under collections – electric fuel adjustment clause	75		66
Environmental remediation costs	38		39
AROs and related funding	307		304
Franchise agreements	34		36
Deferred employee benefit plan costs	399		405
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	141		151
Deferred pollution control costs	38		38
Unrecovered plant	20		20
Other	65		64
Total Regulatory Assets	$	1,365	$	1,377

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Accumulated deferred income taxes	$	20	$	21
Asset removal costs	512		507
Storm damage reserve	27		27
Deferred gains on interest rate derivatives	137		110
Planned major maintenance	1		—
Total Regulatory Liabilities	$	697	$	665

Schedule of Changes in Electric Rate BLRA [Table Text Block]

years indicated:

Year	Action			Amount
2012	2.3	%	Increase	$52.1 million
2011	2.4	%	Increase	$52.8 million

Schedule of Changes in Gas Rate RSA [Table Text Block]

e years indicated:

Year	Action			Amount
2012	2.1	%	Increase	$7.5 million
2011	2.1	%	Increase	$8.6 million

XML

SEGMENT OF BUSINESS INFORMATION

3 Months Ended

Mar. 31, 2013

Segment Reporting Information [Line Items]

Segment Reporting Disclosure [Text Block]

SEGMENT OF BUSINESS INFORMATION

The Company’s reportable segments are listed in the following table.  The Company uses operating income to measure profitability for its regulated operations; therefore, net income is not allocated to the Electric Operations and Gas Distribution segments.  The Company uses net income to measure profitability for its Retail Gas Marketing and Energy Marketing segments.  Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy which meet 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.

Millions of dollars	External Revenue			Intersegment Revenue			Operating Income		Net Income
Three Months Ended March 31, 2013
Electric Operations	$	583		$	2		$	153	n/a
Gas Distribution	379			—			93		n/a
Retail Gas Marketing	179			—			—		$	22
Energy Marketing	167			42			—		3
All Other	12			107			7		3
Adjustments/Eliminations	(9		)	(151		)	40		123
Consolidated Total	$	1,311		—			$	293	$	151

Three Months Ended March 31, 2012
Electric Operations	$	545		$	2		$	127	n/a
Gas Distribution	274			—			83		n/a
Retail Gas Marketing	153			—			n/a		$	11
Energy Marketing	132			26			n/a		2
All Other	11			106			7		5
Adjustments/Eliminations	(8		)	(134		)	21		103
Consolidated Total	$	1,107		$	—		$	238	$	121

	March 31,		December 31,
Segment Assets	2013		2012
Electric Operations	$	9,111	$	8,989
Gas Distribution	2,308		2,292
Retail Gas Marketing	188		153
Energy Marketing	129		122
All Other	1,455		1,415
Adjustments/Eliminations	1,566		1,645
Consolidated Total	$	14,757	$	14,616

SCEG

Segment Reporting Information [Line Items]

Segment Reporting Disclosure [Text Block]

SEGMENT OF BUSINESS INFORMATION

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

					Earnings Available
	External		Operating		To Common
Millions of dollars	Revenue		Income		Shareholder
Three Months Ended March 31, 2013
Electric Operations	$	585	$	153	n/a
Gas Distribution	143		38		n/a
Adjustments/Eliminations	—		—		$	89
Consolidated Total	$	728	$	191	$	89

Three Months Ended March 31, 2012
Electric Operations	$	547	$	127	n/a
Gas Distribution	116		29		n/a
Adjustments/Eliminations	—		—		$	69
Consolidated Total	$	663	$	156	$	69

	March 31,		December 31,
Segment Assets	2013		2012
Electric Operations	$	9,111	$	8,989
Gas Distribution	664		659
Adjustments/Eliminations	2,503		2,456
Consolidated Total	$	12,278	$	12,104

XML

DERIVATIVE FINANCIAL INSTRUMENTS

3 Months Ended

Mar. 31, 2013

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

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. 

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 Audit Committee of the Board of Directors with regard to the management of risk and brings to the Audit Committee's attention significant 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 companies and financial institutions.  Cash settlements of commodity derivatives are classified as operating activities in the condensed consolidated statements of cash flows.

PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options.  PSNC Energy’s tariffs also include a provision for the recovery of actual gas costs incurred, including any costs of hedging.  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 OCI.  When the hedged transactions affect earnings, the previously recorded gains and losses are reclassified from AOCI 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. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes.

Interest Rate Swaps

The Company may use interest rate swaps to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances.  These swaps may be designated as either fair value hedges or cash flow hedges.

The Company synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges. Periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

In anticipation of the issuance of debt, the Company may use treasury rate lock or forward starting swap agreements that 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 OCI.  Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions are recognized in income.  Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes.

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 MMBTU)
Hedge designation	Gas Distribution	Retail Gas Marketing	Energy Marketing	Total
As of March 31, 2013
Cash flow	—	4,074,000	14,344,000	18,418,000
Not designated (a)	4,850,000	—	14,085,848	18,935,848
Total (a)	4,850,000	4,074,000	28,429,848	37,353,848
As of December 31, 2012
Cash flow	—	6,490,000	18,937,000	25,427,000
Not designated (b)	5,170,000	—	17,703,275	22,873,275
Total (b)	5,170,000	6,490,000	36,640,275	48,300,275

(a)  Includes an aggregate 1,850,000 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 3,500,000 MMBTU related to basis swap contracts in Energy Marketing.

The Company was not party to any interest rate swap designated as a fair value hedge during any period presented. The Company was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $1.1 billion at each of March 31, 2013 and December 31, 2012.

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

	Fair Values of Derivative Instruments
	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
Millions of dollars	Location	Value		Location	Value
As of March 31, 2013
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	58	Other current liabilities	$	62
	Other deferred debits and other assets	42		Other deferred credits and other liabilities	33
Commodity	Prepayments and other	2		Prepayments and other	1
Total		$	102		$	96
Derivatives not designated as hedging instruments
Commodity	Prepayments and other	$	2
Energy management	Prepayments and other	5		Other current liabilities	$	5
	Other deferred debits and other assets	5		Other deferred credits and other liabilities	5
Total		$	12		$	10

As of December 31, 2012
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	42	Other current liabilities	$	70
	Other deferred debits and other assets	31		Other deferred credits and other liabilities	36
Commodity	Prepayments and other	1		Other current liabilities	4
Total		$	74		$	110
Derivatives not designated as hedging instruments
Commodity	Prepayments and other	$	1
Energy management	Prepayments and other	7		Prepayments and other	$	1
	Other deferred debits and other assets	6		Other current liabilities	6
				Other deferred debits and other assets	6
Total		$	14		$	13

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

Fair Value Hedges

With regard to the Company's interest rate swaps designated as fair value hedges, any gains or losses related to the swaps or the fixed rate debt are recognized in current earnings and included in interest expense.  Such gains and losses, combined with the amortization of deferred gains on previously terminated swaps, were not significant during any period presented.

Cash Flow Hedges

Derivatives in Cash Flow Hedging Relationships

					Loss Reclassified from
	Gain (Loss) Deferred				Deferred Accounts into Income
	in Regulatory Accounts				(Effective Portion)
Millions of dollars	(Effective Portion)				Location	Amount
	2013		2012			2013			2012
Three Months Ended March 31,
Interest rate	$	35	$	30	Interest expense	$	(1	)	$	(1	)

	Gain (Loss)					Loss Reclassified from
	Recognized in OCI,					AOCI into Income,
	net of tax					net of tax (Effective Portion)
	(Effective Portion)					Location	Amount
	2013		2012				2013			2012
Three Months Ended March 31,
Interest rate	$	1	—			Interest expense	$	(2	)	$	(2	)
Commodity	2		$	(4	)	Gas purchased for resale	(2		)	(8		)
Total	$	3	$	(4	)		$	(4	)	$	(10	)

As of March 31, 2013, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive income (loss) to earnings arising from cash flow hedges will include approximately $0.7 million as a decrease to gas cost and approximately $6.0 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of March 31, 2013, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2015.

Derivatives not designated as Hedging Instruments	Loss Recognized in Income
Millions of dollars	Location	2013		2012
Three Months Ended March 31,
Commodity	Gas purchased for resale	$	—	$	(1	)

Hedge Ineffectiveness

Other losses recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three months ended March 31, 2013 and 2012, respectively.

Credit Risk Considerations

The Company limits credit risk in its commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. In this regard, the Company uses credit ratings provided by credit rating agencies and current market-based qualitative and quantitative data, as well as financial statements, to assess the financial health of counterparties on an ongoing basis. The Company uses standardized master agreements which may include collateral requirements. These master agreements permit the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements (if any) require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with the Company's credit policies and due diligence. In addition, collateral agreements (if any) allow for the termination and liquidation of all positions in the event of a failure or inability to post collateral.

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 March 31, 2013 and December 31, 2012, the Company has posted $60.6 million and $78.3 million, respectively, of collateral related to derivatives with contingent provisions that were in a net liability position.  Collateral related to the positions expected to close in the next 12 months is recorded in Prepayments and other on the consolidated balance sheets. Collateral related to the noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of March 31, 2013 and December 31, 2012, the Company would have been required to post an additional $21.3 million and $26.2 million, respectively, of collateral with its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of March 31, 2013 and December 31, 2012 is $81.9 million and $104.5 million, respectively.

In addition, as of March 31, 2013 and December 31, 2012, the Company has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments were fully triggered as of March 31, 2013 and December 31, 2012, the Company could request $45.6 million and $32.1 million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of March 31, 2013 and December 31, 2012 is $45.6 million and $32.1 million, respectively. In addition, at March 31, 2013, the Company could have called on letters of credit in the amount of $9 million related to $9 million in commodity derivatives that are in a net asset position, compared to letters of credit of $10 million related to derivatives of $13 million at December 31, 2012, if all the contingent features underlying these instruments had been fully triggered.

Information related to the Company's offsetting of derivative assets follows:

								Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position			Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Received		Net Amount
As of March 31, 2013
Interest rate	$	100	—			$	100	$	(22	)	—		$	78
Commodity	4		—			4		—			—		4
Energy management	10		$	(1	)	9		—			—		9
Total	$	114	$	(1	)	$	113	$	(22	)	$	—	$	91
Balance sheet location	Prepayments and other					$	66
	Other deferred debits and other assets					47
	Total					$	113

As of December 31, 2012
Interest rate	$	73	—			$	73	$	(17	)	—		$	56
Commodity	2		—			2		—			—		2
Energy management	$	13	$	(1	)	$	12	$	—		—		$	12
Total	$	88	$	(1	)	$	87	$	(17	)	$	—	$	70
Balance sheet location	Prepayments and other					$	50
	Other deferred debits and other assets					37
	Total					$	87

 Information related to the Company's offsetting of derivative liabilities follows:

								Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position			Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Posted			Net Amount
As of March 31, 2013
Interest rate	$	95	—			$	95	$	(22	)	$	(53	)	$	20
Commodity	1		—			1		—			—			1
Energy management	10		$	(1	)	9		—			(8		)	1
	$	106	$	(1	)	$	105	$	(22	)	$	(61	)	$	22
Balance sheet location	Other current liabilities					$	67
	Other deferred credits and other liabilities					38
	Total					$	105

As of December 31, 2012
Interest rate	$	106	—			$	106	$	(17	)	$	(67	)	$	22
Commodity	4		—			4		—			—			4
Energy management	13		$	(1	)	12		—			(11		)	1
	$	123	$	(1	)	$	122	$	(17	)	$	(78	)	$	27
Balance sheet location	Other current liabilities					$	80
	Other deferred credits and other liabilities					42
	Total					$	122

SCEG

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

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. 

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 Audit Committee of the Board of Directors with regard to the management of risk and brings to the Audit Committee’s attention significant areas of concern.  Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

Interest Rate Swaps

Consolidated SCE&G synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges.  Periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

In anticipation of the issuance of debt, Consolidated SCE&G may use treasury rate lock or forward starting swap agreements that are designated as cash flow hedges.  The effective portions of changes in fair value and payments made or received upon termination of such agreements are recorded in regulatory assets or regulatory liabilities.  Such amounts are amortized to interest expense over the term of the underlying debt.  Ineffective portions are recognized in income.  Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes.

Quantitative Disclosures Related to Derivatives

Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $971.4 million at each of March 31, 2013 and December 31, 2012.

The fair value of interest rate derivatives was reflected in the condensed consolidated balance sheet as follows:

	Fair Values of Derivative Instruments
	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
Millions of dollars	Location	Value		Location	Value
As of March 31, 2013
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	58	Other current liabilities	$	59
	Other deferred debits and other assets	42		Other deferred credits and other liabilities	7
Total		$	100		$	66
As of December 31, 2012
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	42	Other current liabilities	$	66
	Other deferred debits and other assets	31		Other deferred credits and other liabilities	9
Total		$	73		$	75

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

Derivatives in Cash Flow Hedging Relationships	Gain Deferred in Regulatory Accounts				Loss Reclassified from Deferred Accounts into Income (Effective Portion)
Millions of dollars	(Effective Portion)				Location	Amount
Three Months Ended March 31,	2013		2012			2013			2012
Interest rate	$	35	$	30	Interest expense	$	(1	)	$	(1	)

Derivatives not designated as Hedging Instruments	Loss Recognized in Income
Millions of dollars	Location	2013	2012
Three Months Ended March 31,
Commodity	Gas purchased for resale	—	(1	)

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 months ended March 31, 2013 and 2012, respectively.

Credit Risk Considerations

Consolidated SCE&G limits credit risk in its derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. In this regard, Consolidated SCE&G uses credit ratings provided by credit rating agencies and current market-based qualitative and quantitative data as well as financial statements, to assess the financial health of counterparties on an ongoing basis. Consolidated SCE&G uses standardized master agreements which may include collateral requirements. These master agreements permit the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements (if any) require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with Consolidated SCE&G's credit policies and due diligence. In addition, collateral agreements (if any) allow for the termination and liquidation of all positions in the event of a failure or inability to post collateral.

Certain of Consolidated SCE&G’s derivative instruments contain contingent provisions that require Consolidated SCE&G to provide collateral upon the occurrence of specific events, primarily credit downgrades.  As of March 31, 2013 and December 31, 2012, Consolidated SCE&G has posted $22.1 million and $35.2 million, respectively, of collateral related to derivatives with contingent provisions that were in a net liability position.  Collateral related to the positions expected to close in the next 12 months are recorded in Prepayments and other on the consolidated balance sheets. Collateral related to the noncurrent positions are recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of March 31, 2013 and December 31, 2012, Consolidated SCE&G would have been required to post an additional $22.2 million and $22.7 million respectively, of collateral with its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of March 31, 2013 and December 31, 2012 is $44.3 million and $57.9 million, respectively.

In addition, as of March 31, 2013 and December 31, 2012, Consolidated SCE&G has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments were fully triggered as of March 31, 2013 and December 31, 2012, Consolidated SCE&G could request $43.9 million and $32.1 million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of March 31, 2013 and December 31, 2012 is $43.9 million and $32.1 million, respectively.

Information related to Consolidated SCE&G's derivative assets follows:

						Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Received	Net Amount
As of March 31, 2013
Interest rate	$	100	—	$	100	$	(22	)	—	$	78
Balance Sheet Location	Prepayments and other			$	58
	Other deferred debits and other assets			42
	Total			$	100

As of December 31, 2012
Interest rate	$	73	—	$	73	(17	)	—	$	56
Balance Sheet Location	Prepayments and other			$	42
	Other deferred debits and other assets			31
	Total			$	73

Information related to Consolidated SCE&G's derivative liabilities follows:

						Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Posted			Net Amount
As of March 31, 2013
Interest rate	$	66	—	$	66	$	(22	)	$	(22	)	$	22
Balance Sheet Location	Other current liabilities			$	59
	Other deferred credits and other liabilities			7
	Total			$	66

As of December 31, 2012
Interest rate	$	75	—	$	75	$	(17	)	$	(35	)	$	23
Balance Sheet Location	Other current liabilities			$	66
	Other deferred credits and other liabilities			9
	Total			$	75

XML

LONG-TERM AND SHORT-TERM DEBT

3 Months Ended

Mar. 31, 2013

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In January 2013, JEDA issued at a premium, for the benefit of SCE&G, $39.5 million of 4.0% tax-exempt industrial revenue bonds due February 1, 2028, and $14.7 million of 3.63% tax-exempt industrial revenue bonds due February 1, 2033. Proceeds from these sales were loaned by JEDA to SCE&G and, together with other available funds, were used to redeem prior to maturity $56.9 million of 5.2% industrial revenue bonds due November 1, 2027.

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
Millions of dollars	March 31, 2013			December 31, 2012			March 31, 2013			December 31, 2012			March 31, 2013		December 31, 2012
Lines of credit:
Total committed long-term	$	300		$	300		$	1,400		$	1,400		$	100	$	100
LOC advances	—			—			—			—			—		—
Weighted average interest rate	—			—			—			—			—		—
Outstanding commercial paper (270 or fewer days)	$	122		$	142		$	408		$	449		—		$	32
Weighted average interest rate	0.48		%	0.58		%	0.33		%	0.42		%	—		0.44		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—		—
Available	$	175		$	155		$	992		$	951		$	100	$	68

SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million, $1.2 billion (of which $500 million relates to Fuel Company) and $100 million, respectively, which expire in October  2017. In addition, SCE&G is party to a new three-year credit agreement in the amount of $200 million which expires in October 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, certain fossil fuels, 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 10.7% of the aggregate $1.8 billion credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. Credit Suisse AG, Cayman Island Branch and UBS Loan Finance LLC each provide 8.9%, and Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 6.3%.  Two other banks provide the remaining support. The Company pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented.

The Company is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company.  The letters of credit expire, subject to renewal, in the fourth quarter of 2014.

SCEG

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In January 2013, JEDA issued at a premium, for the benefit of SCE&G, $39.5 million of 4.0% tax-exempt industrial revenue bonds due February 1, 2028, and $14.7 million of 3.63% tax-exempt industrial revenue bonds due February 1, 2033. Proceeds from these sales were loaned by JEDA to SCE&G and, together with other available funds, were used to redeem prior to maturity $56.9 million of 5.2% industrial revenue bonds due November 1, 2027.

 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:

Millions of dollars	March 31, 2013			December 31, 2012
Lines of credit:
Total committed long-term	$	1,400		$	1,400
LOC advances	—			—
Weighted average interest rate	—			—
Outstanding commercial paper (270 or fewer days)	$	408		$	449
Weighted average interest rate	0.33		%	0.42		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	992		$	951

SCE&G and Fuel Company are parties to five-year credit agreements in the amount of $1.2 billion (of which $500 million relates to Fuel Company) which expire in October 2017. In addition, SCE&G is party to a new three-year credit agreement in the amount of $200 million, which expires in October 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, certain fossil fuels, 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 10.7% of the aggregate $1.4 billion credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch and UBS Loan Finance LLC each provide 8.9% and Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 6.3%.  Two other banks provide the remaining support. Consolidated SCE&G pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented.

Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company.  The letters of credit expire, subject to renewal, in the fourth quarter of 2014.

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 any period presented. At March 31, 2013 and December 2012, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $48.8 million and $49.4 million, respectively.

XML

INCOME TAXES

3 Months Ended

Mar. 31, 2013

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

 In connection with a prior change in method of tax accounting for certain repair costs, the Company had previously recorded an unrecognized tax benefit of $38 million. Under newadministrative guidance from the Internal Revenue Service, the Company recognized all of the previously unrecognized tax benefit in the first quarter of 2012. Since this change was primarily a temporary difference, the recognition of this benefit did not have a significant effect on the Company's effective tax rate. No other material changes in the status of the Company's tax positions have occurred through March 31, 2013.

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. In connection with the resolution of the uncertainty and recognition of tax benefits described above, during the quarter ended March 31, 2012, the Company reversed $2 million of interest expense which had been accrued during 2011.

SCEG

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

In connection with a prior change in method of tax accounting for certain repair costs, Consolidated SCE&G had previously recorded an unrecognized tax benefit of $38 million. Under newadministrative guidance from the Internal Revenue Service, Consolidated SCE&G recognized all of the previously unrecognized tax benefit in the first quarter of 2012. Since this change was primarily a temporary difference, the recognition of this benefit did not have a significant effect on Consolidated SCE&G's effective tax rate. No other material changes in the status of Consolidated SCE&G's tax positions have occurred through March 31, 2013.

Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. In connection with the resolution of the uncertainty and recognition of tax benefits described above, during the quarter ended March 31, 2012, Consolidated SCE&G reversed $2 million of interest expense which had been accrued during 2011.

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

3 Months Ended

Mar. 31, 2013

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Disclosures [Text Block]

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 and energy management 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 market data.  Fair value measurements, and the level within the fair value hierarchyin 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 March 31, 2013
Assets -	Available for sale securities	$7	—
	Interest rate contracts	—	$100
	Commodity contracts	2	2
	Energy management contracts	1	9
Liabilities -	Interest rate contracts	—	95
	Commodity contracts	—	1
	Energy management contracts	—	13
As of December 31, 2012
Assets -	Available for sale securities	$6	—
	Interest rate contracts	—	$73
	Commodity contracts	1	1
	Energy management contracts	—	13
Liabilities -	Interest rate contracts	—	106
	Commodity contracts	—	4
	Energy management contracts	1	15

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, 2 or 3 during the periods presented.

Financial instruments for which the carrying amount may not equal estimated fair value at March 31, 2013 and December 31, 2012 were as follows:

	March 31, 2013				December 31, 2012
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	5,211.7	$	6,118.8	$	5,121.0	$	6,115.0

Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates.  As such, the aggregate fair values presented above are considered to be Level 2.  Carrying values reflect the fair values of interest rate swaps designated as fair value hedges, based on discounted cash flow models with independently sourced market data.  Early settlement of long-term debt may not be possible or may not be considered prudent.

Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2.

SCEG

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Disclosures [Text Block]

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

Consolidated SCE&G’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data.  Fair value measurements based on significant other observable inputs (level 2) were as follows: 

		Fair Value Measurements Using Significant
		Other Observable Inputs (Level 2)
Millions of dollars		March 31, 2013	December 31, 2012
Assets -	Interest rate contracts	$100	$73
Liabilities -	Interest rate contracts	66	75

There were no fair value measurements based on quoted prices in active markets for identical assets (Level 1) or 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, 2 or 3 during the periods presented.

Financial instruments for which the carrying amount may not equal estimated fair value at March 31, 2013 and December 31, 2012 were as follows:

	March 31, 2013				December 31, 2012
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,811.0	$	4,534.8	$	3,722.0	$	4,543.1

Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates.  As such, the aggregate fair values presented above are considered to be Level 2.  Carrying values reflect the fair values of interest rate swaps designated as fair value hedges, based on discounted cash flow models with independently sourced market data.  Early settlement of long-term debt may not be possible or may not be considered prudent.

Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2.

XML

COMMON EQUITY (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012		Dec. 31, 2012	Dec. 31, 2011	Sep. 30, 2010
Schedule of Capitalization, Equity [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	$ (4)		$ (10)
Common Stock, Shares Authorized	200,000,000
COMMON EQUITY [Abstract]
Common Shareholders' Equity	4,463				4,154
Forward Contract Indexed to Issuer's Equity, Indexed Shares							6,600,000
Dividends declared	(70)		(65)
Total Comprehensive Income (Loss)	158	[1]	127	[1]
Common Stock, Shares, Outstanding	139,200,000				132,000,000
Proceeds from exercise of equity forward sales agreements	196.2
Common stock issued	221		26
Common Stockholders' Equity			3,977			3,889
SCEG
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	50,000,000				50,000,000
COMMON EQUITY [Abstract]
Stockholders' Equity Attributable to Noncontrolling Interest	115				114
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	4,292		3,816		4,043	3,773
Proceeds from Contributions from Parent	221		24
Dividends	(64)		(53)
Total Comprehensive Income (Loss)	92		72
Common Stock, Shares, Outstanding	40,300,000				40,300,000
Preferred Stock, Shares Authorized	20,000,000				20,000,000
Preferred Stock, Shares Outstanding	1,000				1,000
SCE&G (including Fuel Company)
COMMON EQUITY [Abstract]
Proceeds from Contributions from Parent	221		24
Dividends	(62)		(51)
Common Shareholders' Equity	4,177		3,707		3,929	3,665
Total Comprehensive Income (Loss)	89		69
Genco
COMMON EQUITY [Abstract]
Stockholders' Equity Attributable to Noncontrolling Interest	115		109		114	108
Proceeds from Contributions from Parent	0		0
Dividends	(2)		(2)
Total Comprehensive Income (Loss)	3		3
Interest Rate Contract
Schedule of Capitalization, Equity [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	(2)		(2)
Commodity Contract
Schedule of Capitalization, Equity [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	$ (2)		$ (8)

[1] Accumulated other comprehensive loss totaled $78.8 million as of March 31, 2013 and $85.6 million as of December 31, 2012.

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

3 Months Ended

Mar. 31, 2013

Significant Accounting Policies

Use of Estimates

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.

Asset Management and Supply Service Agreements

Asset Management and Supply Service Agreements

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities.  Such counterparties held 18% and 44% of PSNC Energy’s natural gas inventory at March 31, 2013

and December 31, 2012, respectively, with a carrying value of $3.4 million and $19.6 million, respectively, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees. The agreements expire at various times through March 31, 2015.

Earnings Per Share

Earnings Per Share

The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period.  The Company computes diluted earnings per share using this same formula after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method.  The Company has issued no securities that would have an antidilutive effect on earnings per share.

SCEG

Significant Accounting Policies

Income Tax, Policy [Policy Text Block]

Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.

Consolidation, Variable Interest Entity, Policy [Policy Text Block]

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, pursuant to a FERC-approved tariff, 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 $472 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances. See also Note 4.

Use of Estimates

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.

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

3 Months Ended

Mar. 31, 2013

Derivative [Line Items]

Schedule of Derivative Instruments [Table Text Block]

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

	Commodity and Other Energy Management Contracts (in MMBTU)
Hedge designation	Gas Distribution	Retail Gas Marketing	Energy Marketing	Total
As of March 31, 2013
Cash flow	—	4,074,000	14,344,000	18,418,000
Not designated (a)	4,850,000	—	14,085,848	18,935,848
Total (a)	4,850,000	4,074,000	28,429,848	37,353,848
As of December 31, 2012
Cash flow	—	6,490,000	18,937,000	25,427,000
Not designated (b)	5,170,000	—	17,703,275	22,873,275
Total (b)	5,170,000	6,490,000	36,640,275	48,300,275

(a)  Includes an aggregate 1,850,000 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 3,500,000 MMBTU related to basis swap contracts in Energy Marketing.

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

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

	Fair Values of Derivative Instruments
	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
Millions of dollars	Location	Value		Location	Value
As of March 31, 2013
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	58	Other current liabilities	$	62
	Other deferred debits and other assets	42		Other deferred credits and other liabilities	33
Commodity	Prepayments and other	2		Prepayments and other	1
Total		$	102		$	96
Derivatives not designated as hedging instruments
Commodity	Prepayments and other	$	2
Energy management	Prepayments and other	5		Other current liabilities	$	5
	Other deferred debits and other assets	5		Other deferred credits and other liabilities	5
Total		$	12		$	10

As of December 31, 2012
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	42	Other current liabilities	$	70
	Other deferred debits and other assets	31		Other deferred credits and other liabilities	36
Commodity	Prepayments and other	1		Other current liabilities	4
Total		$	74		$	110
Derivatives not designated as hedging instruments
Commodity	Prepayments and other	$	1
Energy management	Prepayments and other	7		Prepayments and other	$	1
	Other deferred debits and other assets	6		Other current liabilities	6
				Other deferred debits and other assets	6
Total		$	14		$	13

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

Derivatives in Cash Flow Hedging Relationships

					Loss Reclassified from
	Gain (Loss) Deferred				Deferred Accounts into Income
	in Regulatory Accounts				(Effective Portion)
Millions of dollars	(Effective Portion)				Location	Amount
	2013		2012			2013			2012
Three Months Ended March 31,
Interest rate	$	35	$	30	Interest expense	$	(1	)	$	(1	)

	Gain (Loss)					Loss Reclassified from
	Recognized in OCI,					AOCI into Income,
	net of tax					net of tax (Effective Portion)
	(Effective Portion)					Location	Amount
	2013		2012				2013			2012
Three Months Ended March 31,
Interest rate	$	1	—			Interest expense	$	(2	)	$	(2	)
Commodity	2		$	(4	)	Gas purchased for resale	(2		)	(8		)
Total	$	3	$	(4	)		$	(4	)	$	(10	)

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

Derivatives not designated as Hedging Instruments	Loss Recognized in Income
Millions of dollars	Location	2013		2012
Three Months Ended March 31,
Commodity	Gas purchased for resale	$	—	$	(1	)

Offseting Assets [Table Text Block]

Information related to the Company's offsetting of derivative assets follows:

								Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position			Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Received		Net Amount
As of March 31, 2013
Interest rate	$	100	—			$	100	$	(22	)	—		$	78
Commodity	4		—			4		—			—		4
Energy management	10		$	(1	)	9		—			—		9
Total	$	114	$	(1	)	$	113	$	(22	)	$	—	$	91
Balance sheet location	Prepayments and other					$	66
	Other deferred debits and other assets					47
	Total					$	113

As of December 31, 2012
Interest rate	$	73	—			$	73	$	(17	)	—		$	56
Commodity	2		—			2		—			—		2
Energy management	$	13	$	(1	)	$	12	$	—		—		$	12
Total	$	88	$	(1	)	$	87	$	(17	)	$	—	$	70
Balance sheet location	Prepayments and other					$	50
	Other deferred debits and other assets					37
	Total					$	87

Offsetting Liabilities [Table Text Block]

 Information related to the Company's offsetting of derivative liabilities follows:

								Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position			Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Posted			Net Amount
As of March 31, 2013
Interest rate	$	95	—			$	95	$	(22	)	$	(53	)	$	20
Commodity	1		—			1		—			—			1
Energy management	10		$	(1	)	9		—			(8		)	1
	$	106	$	(1	)	$	105	$	(22	)	$	(61	)	$	22
Balance sheet location	Other current liabilities					$	67
	Other deferred credits and other liabilities					38
	Total					$	105

As of December 31, 2012
Interest rate	$	106	—			$	106	$	(17	)	$	(67	)	$	22
Commodity	4		—			4		—			—			4
Energy management	13		$	(1	)	12		—			(11		)	1
	$	123	$	(1	)	$	122	$	(17	)	$	(78	)	$	27
Balance sheet location	Other current liabilities					$	80
	Other deferred credits and other liabilities					42
	Total					$	122

SCEG

Derivative [Line Items]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

The fair value of interest rate derivatives was reflected in the condensed consolidated balance sheet as follows:

	Fair Values of Derivative Instruments
	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
Millions of dollars	Location	Value		Location	Value
As of March 31, 2013
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	58	Other current liabilities	$	59
	Other deferred debits and other assets	42		Other deferred credits and other liabilities	7
Total		$	100		$	66
As of December 31, 2012
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	42	Other current liabilities	$	66
	Other deferred debits and other assets	31		Other deferred credits and other liabilities	9
Total		$	73		$	75

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

Derivatives in Cash Flow Hedging Relationships	Gain Deferred in Regulatory Accounts				Loss Reclassified from Deferred Accounts into Income (Effective Portion)
Millions of dollars	(Effective Portion)				Location	Amount
Three Months Ended March 31,	2013		2012			2013			2012
Interest rate	$	35	$	30	Interest expense	$	(1	)	$	(1	)

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

Derivatives not designated as Hedging Instruments	Loss Recognized in Income
Millions of dollars	Location	2013	2012
Three Months Ended March 31,
Commodity	Gas purchased for resale	—	(1	)

Offseting Assets [Table Text Block]

Information related to Consolidated SCE&G's derivative assets follows:

						Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Received	Net Amount
As of March 31, 2013
Interest rate	$	100	—	$	100	$	(22	)	—	$	78
Balance Sheet Location	Prepayments and other			$	58
	Other deferred debits and other assets			42
	Total			$	100

As of December 31, 2012
Interest rate	$	73	—	$	73	(17	)	—	$	56
Balance Sheet Location	Prepayments and other			$	42
	Other deferred debits and other assets			31
	Total			$	73

Offsetting Liabilities [Table Text Block]

Information related to Consolidated SCE&G's derivative liabilities follows:

						Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Posted			Net Amount
As of March 31, 2013
Interest rate	$	66	—	$	66	$	(22	)	$	(22	)	$	22
Balance Sheet Location	Other current liabilities			$	59
	Other deferred credits and other liabilities			7
	Total			$	66

As of December 31, 2012
Interest rate	$	75	—	$	75	$	(17	)	$	(35	)	$	23
Balance Sheet Location	Other current liabilities			$	66
	Other deferred credits and other liabilities			9
	Total			$	75

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets, Fair Value Disclosure [Abstract]
Available-for-sale Securities	$ 7,000,000	$ 6,000,000
Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest Rate Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Assets		1,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other energy management contracts
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	2,000,000	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	1,000,000
Fair Value, Inputs, Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Available-for-sale Securities	0	0
Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	100,000,000	73,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	95,000,000	106,000,000
Fair Value, Inputs, Level 2 [Member] | Commodity Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	2,000,000	1,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	1,000,000	4,000,000
Fair Value, Inputs, Level 2 [Member] | Other energy management contracts
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	9,000,000	13,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	13,000,000	15,000,000
SCEG | Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	100	73
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	$ 66	$ 75

XML

CONSOLIDATED STATEMENTS OF INCOME CONSOLIDATED STATEMENT OF INCOME (PARENTHETICAL) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Allowance for Funds Used During Construction, Capitalized Interest	$ 2	$ 2
SCEG
Allowance for Funds Used During Construction, Capitalized Interest	$ 2	$ 2

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

Mar. 31, 2013

Significant Accounting Policies

Significant Accounting Policies [Text Block]

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.

Plant to be Retired

SCE&G has six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units have an aggregate generating capacity (summer 2012) of 730 MW. One unit (90 MW) has been retired and its value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units totaled $359 million at March 31, 2013 and is included in Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.

Earnings Per Share

The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period.  The Company computes diluted earnings per share using this same formula after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method.  The Company has issued no securities that would have an antidilutive effect on earnings per share.

Reconciliations of the weighted average number of common shares for basic and diluted earnings per share computation purposes are as follows:

Millions	2013	2012
Weighted Average Shares Outstanding - Basic	134.4	130.3
Net effect of dilutive equity forward shares	1.7	1.9
Weighted Average Shares - Diluted	136.1	132.2

Asset Management and Supply Service Agreements

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities.  Such counterparties held 18% and 44% of PSNC Energy’s natural gas inventory at March 31, 2013

and December 31, 2012, respectively, with a carrying value of $3.4 million and $19.6 million, respectively, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees. The agreements expire at various times through March 31, 2015.

SCEG

Significant Accounting Policies

Significant Accounting Policies [Text Block]

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.

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, pursuant to a FERC-approved tariff, 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 $472 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances. See also Note 4.

Plant to be Retired

SCE&G has six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units have an aggregate generating capacity (summer 2012) of 730 MW. One unit (90 MW) has been retired and its value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units totaled $359 million at March 31, 2013 and is included in Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)

3 Months Ended

Mar. 31, 2013

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair Value, Measurement Inputs, Disclosure [Table Text Block]

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 and energy management 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 market data.  Fair value measurements, and the level within the fair value hierarchyin 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 March 31, 2013
Assets -	Available for sale securities	$7	—
	Interest rate contracts	—	$100
	Commodity contracts	2	2
	Energy management contracts	1	9
Liabilities -	Interest rate contracts	—	95
	Commodity contracts	—	1
	Energy management contracts	—	13
As of December 31, 2012
Assets -	Available for sale securities	$6	—
	Interest rate contracts	—	$73
	Commodity contracts	1	1
	Energy management contracts	—	13
Liabilities -	Interest rate contracts	—	106
	Commodity contracts	—	4
	Energy management contracts	1	15

Fair Value, by Balance Sheet Grouping [Table Text Block]

Financial instruments for which the carrying amount may not equal estimated fair value at March 31, 2013 and December 31, 2012 were as follows:

	March 31, 2013				December 31, 2012
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	5,211.7	$	6,118.8	$	5,121.0	$	6,115.0

SCEG

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair Value, Measurement Inputs, Disclosure [Table Text Block]

Consolidated SCE&G’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data.  Fair value measurements based on significant other observable inputs (level 2) were as follows: 

		Fair Value Measurements Using Significant
		Other Observable Inputs (Level 2)
Millions of dollars		March 31, 2013	December 31, 2012
Assets -	Interest rate contracts	$100	$73
Liabilities -	Interest rate contracts	66	75

Fair Value, by Balance Sheet Grouping [Table Text Block]

Financial instruments for which the carrying amount may not equal estimated fair value at March 31, 2013 and December 31, 2012 were as follows:

	March 31, 2013				December 31, 2012
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,811.0	$	4,534.8	$	3,722.0	$	4,543.1

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013 MMBTU		Dec. 31, 2012 MMBTU
Derivative [Line Items]
Derivative Cash Flow Hedge, Nonmonetary Notional Amount	18,418,000		25,427,000
Derivative not designated as hedging, notional amount	18,935,848	[1]	22,873,275	[2]
Derivative, Nonmonetary Notional Amount	37,353,848	[1]	48,300,275	[2]
Nonmonetary Notional Amount of Basis Swap, Price Risk Derivative Instruments Not Designated as Hedging Instruments	1,850,000		3,500,000
Aggregate notional amount of interest rate swaps designated as cash flow hedge (in dollars)	$ 1,100.0		$ 1,100.0
Gas Distribution
Derivative [Line Items]
Derivative Cash Flow Hedge, Nonmonetary Notional Amount	0		0
Derivative not designated as hedging, notional amount	4,850,000		5,170,000
Derivative, Nonmonetary Notional Amount	4,850,000		5,170,000
Retail Gas Marketing
Derivative [Line Items]
Derivative Cash Flow Hedge, Nonmonetary Notional Amount	4,074,000		6,490,000
Derivative not designated as hedging, notional amount	0		0
Derivative, Nonmonetary Notional Amount	4,074,000		6,490,000
Energy Marketing
Derivative [Line Items]
Derivative Cash Flow Hedge, Nonmonetary Notional Amount	14,344,000		18,937,000
Derivative not designated as hedging, notional amount	14,085,848	[1]	17,703,275	[2]
Derivative, Nonmonetary Notional Amount	28,429,848	[1]	36,640,275	[2]
SCEG
Derivative [Line Items]
Aggregate notional amount of interest rate swaps designated as fair value hedge (in dollars)	971.4
Aggregate notional amount of interest rate swaps designated as cash flow hedge (in dollars)			$ 971.4

[1] (a) Includes an aggregate 1,850,000 MMBTU related to basis swap contracts in Energy Marketing.

[2] (b) Includes an aggregate 3,500,000 MMBTU related to basis swap contracts in Energy Marketing.

XML

AFFILIATED TRANSACTIONS - SCEG

3 Months Ended

Mar. 31, 2013

AFFILIATED TRANSACTIONS

AFFILIATED TRANSACTIONS

CGT transports natural gas to SCE&G to serve SCE&G’s retail gas customers and certain electric generation requirements.  Transportation services totaled approximately $8.4 million and $10.0 million for the three months ended March 31, 2013 and 2012, respectively.  SCE&G had approximately $3.2 million and $3.4 million payable to CGT for transportation services at March 31, 2013 and December 31, 2012, respectively.

SCE&G purchases natural gas and related pipeline capacity from SEMI to serve its retail gas customers and certain electric generation requirements.  Such purchases totaled approximately $42.1 million and $25.4 million for the three months ended March 31, 2013 and 2012, respectively.  SCE&G’s payables to SEMI for such purposes were $14.1 million and $13.1 million as of March 31, 2013 and December 31, 2012, respectively.

SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G owned 10% of Cope Refined Coal, LLC through December 31, 2012. SCE&G accounts for these investments using the equity method.  SCE&G’s receivables from these affiliates were $7.9 million at March 31, 2013 and $1.8 million at December 31, 2012.  SCE&G’s payables to these affiliates were $8.0 million at March 31, 2013 and $1.8 million at December 31, 2012.  SCE&G’s total purchases from these affiliates were $14.3 million and $27.1 million for the three months ended March 31, 2013 and 2012, respectively.  SCE&G’s total sales to these affiliates were $14.3 million and $26.9 million for the three months ended March 31, 2013 and 2012, respectively.

Consolidated SCE&G receives the following services from SCANA Services and its parent company, which are rendered at direct or allocated cost: information systems services, customer services, marketing and sales, human resources, corporate compliance, purchasing, financial services, risk management, public affairs, legal services, investor relations, gas supply and capacity management, strategic planning, general administrative services, and retirement benefits. Consolidated SCE&G’s payables for such purposes were $45.2 million and $45.8 million as of March 31, 2013 and December 31, 2012, respectively.

Money pool borrowings from an affiliate are described at Note 4.