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 September 30, 2014

Commission	Registrant, State of Incorporation,	I.R.S. Employer
File Number	Address and Telephone Number	Identification No.
1-8809	SCANA Corporation (a South Carolina corporation)	57-0784499
1-3375	South Carolina Electric & Gas Company (a South Carolina corporation)	57-0248695
	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 October 31, 2014
SCANA Corporation	Without Par Value	142,550,214
South Carolina Electric & Gas Company	Without Par Value	40,296,147 (a)

(a) Held beneficially and of record by SCANA Corporation.

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

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

TABLE OF CONTENTS 

SEPTEMBER 30, 2014

			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	33
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38
	Item 4.	Controls and Procedures	39
South Carolina Electric & Gas Company Financial Section			40
	Item 1.	Financial Statements	41
		Condensed Consolidated Balance Sheets	41
		Condensed Consolidated Statements of Income	43
		Condensed Consolidated Statements of Comprehensive Income	44
		Condensed Consolidated Statements of Cash Flows	45
		Notes to Condensed Consolidated Financial Statements	46
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	61
	Item 4.	Controls and Procedures	65
PART II. OTHER INFORMATION			65
	Item 5.	Other Information	65
	Item 6.	Exhibits	65
Signatures			67
Exhibit Index			68

2

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Statements included in this Quarterly Report on Form 10-Q which are not statements of historical fact are intended to be, and are hereby identified as, “forward-looking statements” for purposes of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  Forward-looking statements include, but are not limited to, statements concerning key earnings drivers, customer growth, environmental regulations and expenditures, leverage ratio, projections for pension fund contributions, financing activities, access to sources of capital, impacts of the adoption of new accounting rules and estimated construction and other expenditures.  In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “forecasts,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential” or “continue” or the negative of these terms or other similar terminology.  Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements.  Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following:

(1) the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment;

(2) regulatory actions, particularly changes in rate regulation, regulations governing electric grid reliability and pipeline

integrity, 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) the loss of sales to distributed generation, such as solar photovoltaic systems;

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

(9)the results of short- and long-term financing efforts, including prospects for obtaining access to capital markets and

other sources of liquidity;

(10) the effects of weather, 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) changes in SCANA’s or its subsidiaries’ accounting rules and accounting policies;

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

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

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

(15) the ability of suppliers, both domestic and international, to timely provide the labor, secure processes, components,

parts, tools, equipment and other supplies needed, at agreed upon prices, for our construction program, operations and

maintenance;

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

(17) 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;

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

businesses;

(19) labor disputes;

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

(21) changes in taxes and tax credits, including production tax credits for new nuclear units;

(22) inflation or deflation;

(23) compliance with regulations;

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

(25) the other risks and uncertainties described from time to time in the periodic reports filed by SCANA or SCE&G with

the SEC.

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

3

DEFINITIONS

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

TERM	MEANING
AFC	Allowance for Funds Used During Construction
ANI	American Nuclear Insurers
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement Obligation
BLRA	Base Load Review Act
CA	The designation for a specific pre-fabricated construction module, such as module CA20
CAA	Clean Air Act, as amended
CAIR	Clean Air Interstate Rule
CCR	Coal Combustion Residuals
CEO	Chief Executive Officer
CFO	Chief Financial Officer
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act
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 Electric Company LLC and Stone and Webster, Inc., a subsidiary of Chicago Bridge & Iron Company N.V.
Court of Appeals	United States Court of Appeals for the District of Columbia
CSAPR	Cross-State Air Pollution Rule
CUT	Customer Usage Tracker
CWA	Clean Water Act
DHEC	South Carolina Department of Health and Environmental Control
DOE	United States Department of Energy
DSM Programs	Demand reduction and energy efficiency programs
ELG Rule	New federal effluent limitation guidelines for steam electric generating units
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
FERC	United States Federal Energy Regulatory Commission
Fuel Company	South Carolina Fuel Company, Inc.
GENCO	South Carolina Generating Company, Inc.
GPSC	Georgia Public Service Commission
GWh	Gigawatt hour
IRP	Integrated Resource Plan
IRS	Internal Revenue Service
JEDA	South Carolina Jobs-Economic Development Authority
Level 1	A fair value measurement using unadjusted quoted prices in active markets for identical assets or liabilities
Level 2	A fair value measurement using observable inputs other than those for Level 1, including quoted prices for similar (not identical) assets or liabilities or inputs that are derived from observable market data by correlation or other means
Level 3	A fair value measurement using unobservable inputs, including situations where there is little, if any, market activity for the asset or liability
LOC	Lines of Credit
MGP	Manufactured Gas Plant
MMBTU	Million British Thermal Units

4

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
NPDES	National Permit Discharge Elimination System
NRC	United States Nuclear Regulatory Commission
NSPS	New Source Performance Standards
Nuclear Waste Act	Nuclear Waste Policy Act of 1982
NYMEX	New York Mercantile Exchange
OCI	Other Comprehensive Income
ORS	South Carolina Office of Regulatory Staff
PGA	Purchased Gas Adjustment
Price-Anderson	Price-Anderson Indemnification Act
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.
SIP	State Implementation Plan
Summer Station	V. C. Summer Nuclear Station
U. S. Supreme Court	Supreme Court of the United States
VIE	Variable Interest Entity
WNA	Weather Normalization Adjustment

5

SCANA CORPORATION

FINANCIAL SECTION

6

PART I.  FINANCIAL INFORMATION

ITEM 1. F INANCIAL STATEMENTS

SCANA CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited) 

Millions of dollars	September 30, 2014			December 31, 2013
Assets
Utility Plant In Service	$	12,442		$	12,213
Accumulated Depreciation and Amortization	(4,150		)	(4,011		)
Construction Work in Progress	3,232			2,724
Plant to be Retired, Net	167			177
Nuclear Fuel, Net of Accumulated Amortization	282			310
Goodwill, net of writedown of $230	230			230
Utility Plant, Net	12,203			11,643
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $156 and $150	314			317
Assets held in trust, net-nuclear decommissioning	109			101
Other investments	88			86
Nonutility Property and Investments, Net	511			504
Current Assets:
Cash and cash equivalents	82			136
Receivables, net of allowance for uncollectible accounts of $6 and $6	690			802
Inventories (at average cost):
Fuel and gas supply	213			232
Materials and supplies	143			131
Prepayments and other	231			120
Total Current Assets	1,359			1,421
Deferred Debits and Other Assets:
Regulatory assets	1,564			1,360
Pension asset	55			47
Other	179			189
Total Deferred Debits and Other Assets	1,798			1,596
Total	$	15,871		$	15,164

See Notes to Condensed Consolidated Financial Statements.

7

Millions of dollars	September 30, 2014			December 31, 2013
Capitalization and Liabilities
Common Stock - no par value (shares outstanding: September 30, 2014 - 142.2 million; December 31, 2013 - 140.7 million)	$	2,355		$	2,280
Retained Earnings	2,654			2,444
Accumulated Other Comprehensive Loss	(61		)	(60		)
Total Common Equity	4,948			4,664
Long-Term Debt, net	5,681			5,395
Total Capitalization	10,629			10,059
Current Liabilities:
Short-term borrowings	487			376
Current portion of long-term debt	52			54
Accounts payable	387			425
Customer deposits and customer prepayments	96			88
Taxes accrued	137			206
Interest accrued	79			82
Dividends declared	72			69
Derivative financial instruments	113			8
Other	113			134
Total Current Liabilities	1,536			1,442
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,781			1,703
Deferred investment tax credits	29			32
Asset retirement obligations	592			576
Postretirement benefits	224			227
Regulatory liabilities	857			966
Other	223			159
Total Deferred Credits and Other Liabilities	3,706			3,663
Commitments and Contingencies (Note 9)	—			—
Total	$	15,871		$	15,164

See Notes to Condensed Consolidated Financial Statements.

8

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Millions of dollars, except per share amounts	2014			2013			2014			2013
Operating Revenues:
Electric	$	739		$	704		$	2,027		$	1,898
Gas - regulated	132			128			740			667
Gas - nonregulated	250			219			969			813
Total Operating Revenues	1,121			1,051			3,736			3,378
Operating Expenses:
Fuel used in electric generation	212			196			636			570
Purchased power	13			19			54			35
Gas purchased for resale	304			265			1,291			1,076
Other operation and maintenance	169			167			523			513
Depreciation and amortization	96			95			286			282
Other taxes	58			54			174			164
Total Operating Expenses	852			796			2,964			2,640
Operating Income	269			255			772			738
Other Income (Expense):
Other income	18			10			103			36
Other expense	(12		)	(10		)	(39		)	(32		)
Interest charges, net of allowance for borrowed funds used during construction of $5, $4, $13 and $10	(79		)	(74		)	(231		)	(223		)
Allowance for equity funds used during construction	11			9			26			19
Total Other Expense	(62		)	(65		)	(141		)	(200		)
Income Before Income Tax Expense	207			190			631			538
Income Tax Expense	63			59			198			170
Net Income	$	144		$	131		$	433		$	368
Per Common Share Data
Basic Earnings Per Share of Common Stock	$	1.01		$	0.94		$	3.06		$	2.67
Diluted Earnings Per Share of Common Stock	$	1.01		$	0.94		$	3.06		$	2.66
Weighted Average Common Shares Outstanding (millions)
Basic	142.1			140.1			141.6			138.0
Diluted	142.1			140.1			141.6			138.6
Dividends Declared Per Share of Common Stock	$	0.5250		$	0.5075		$	1.5750		$	1.5225

See Notes to Condensed Consolidated Financial Statements.

9

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited) 

	Three Months Ended September 30,						Nine Months Ended September 30,
Millions of dollars	2014			2013			2014			2013
Net Income	$	144		$	131		$	433		$	368
Other Comprehensive Income (Loss), net of tax:
Unrealized Gains (Losses) on Cash Flow Hedging Activities:
Unrealized gains (losses) on cash flow hedging activities arising during period, net of tax of $(1), $-, $(2) and $2	(2		)	(1		)	(3		)	3
Losses on cash flow hedging activities reclassified to net income, net of tax of $1, $1, $- and $4	2			2			1			7
Employee benefit plan remeasurement and curtailment gains arising during the period, net of tax of $-,$2, $-, and $2	—			4			—			4
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax of $-, $-, $- and $-	1			1			1			1
Other Comprehensive Income (Loss)	1			6			(1		)	15
Total Comprehensive Income	$	145		$	137		$	432		$	383

See Notes to Condensed Consolidated Financial Statements.

10

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited) 

	Nine Months Ended September 30,
Millions of dollars	2014			2013
Cash Flows From Operating Activities:
Net income	$	433		$	368
Adjustments to reconcile net income to net cash provided from operating activities:
Losses from equity method investments	2			—
Deferred income taxes, net	63			62
Depreciation and amortization	298			294
Amortization of nuclear fuel	31			42
Allowance for equity funds used during construction	(26		)	(19		)
Carrying cost recovery	(7		)	—
Changes in certain assets and liabilities:	—
Receivables	111			70
Inventories	(34		)	(8		)
Prepayments and other	(90		)	8
Regulatory liabilities	(133		)	78
Accounts payable	(18		)	(32		)
Taxes accrued	(69		)	(27		)
Interest accrued	(3		)	(7		)
Pension and other post retirement benefits	(13		)	(133		)
Regulatory assets	(171		)	142
Other assets	16			(46		)
Other liabilities	168			(13		)
Net Cash Provided From Operating Activities	558			779
Cash Flows From Investing Activities:
Property additions and construction expenditures	(778		)	(868		)
Proceeds from investments (including derivative collateral posted)	204			199
Purchase of investments (including derivative collateral posted)	(247		)	(161		)
Proceeds from interest rate contract settlement	—			43
Payments upon interest rate contract settlement	(34		)	(49		)
Net Cash Used For Investing Activities	(855		)	(836		)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock	75			272
Proceeds from issuance of long-term debt	294			451
Repayment of long-term debt	(17		)	(256		)
Dividends	(220		)	(207		)
Short-term borrowings, net	111			(245		)
Net Cash Provided From Financing Activities	243			15
Net Decrease In Cash and Cash Equivalents	(54		)	(42		)
Cash and Cash Equivalents, January 1	136			72
Cash and Cash Equivalents, September 30	$	82		$	30
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $13 and $10)	$	225		$	222
– Income taxes	246			70
Noncash Investing and Financing Activities:
Accrued construction expenditures	108			97
Capital leases	4			5
Nuclear fuel purchase	—			98

 See Notes to Condensed Consolidated Financial Statements.

11

SCANA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the Three and Nine Months Ended September 30, 2014 and 2013

(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, 2013. 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

In 2012 SCE&G identified six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. Three of these units had been retired by December 31, 2013, and their net carrying value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units is identified as Plant to be Retired, Net in the condensed 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 use and in rate base, and SCE&G depreciates 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:     

	Third Quarter		Year to Date
Millions	2014	2013	2014	2013
Weighted Average Shares Outstanding - Basic	142.1	140.1	141.6	138.0
Effect of dilutive equity forward shares	—	—	—	0.6
Weighted Average Shares - Diluted	142.1	140.1	141.6	138.6

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 47% and 48% of PSNC Energy’s natural gas inventory at September 30, 2014

and December 31, 2013, respectively, with a carrying value of $25.4 million and $22.8 million, respectively, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management feesof which 75% are credited to rate payers. No fees are received under supply service agreements. The agreements expire March 31, 2015. 

12

New Accounting Matter

In May 2014, the Financial Accounting Standards Board issued new accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The Company will be required to adopt the new guidance in the first quarter of 2017, and early adoption is not permitted.  The Company has not determined the impact this guidance will have on its results of operations, cash flows or financial position.

2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric - Cost of Fuel

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 connection with its annual review of base rates for fuel costs, and by order dated April 30, 2013, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC in which SCE&G agreed to reduce its environmental fuel cost component effective with the first billing cycle of May 2013. The order also provided for the accrual of certain debt-related carrying costs on a portion of SCE&G's under-collected balance of fuel costs, and approved SCE&G's total fuel cost component.

By order dated April 29, 2014, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC in which SCE&G agreed to increase its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014.  The SCPSC's order also provided for, among other things, the application of approximately $46 million in deferred gains from the late 2013 settlement of certain interest rate swaps, previously recorded as regulatory liabilities, to reduce the under-collected balance of fuel costs in April 2014 and the accrual of certain debt-related carrying costs on its under-collected balance of base fuel costs during the period May 1, 2014 through April 30, 2015. 

The increase to the base fuel cost component was offset by a reduction in SCE&G’s rate rider related to pension costs, which was approved by the SCPSC in March 2014. The reduction was requested by SCE&G as a result of lower net periodic benefit costs in 2014. See also Note 8.

               The cost of fuel includes amounts paid by SCE&G pursuant to the Nuclear Waste Act for the disposal of spent nuclear fuel.  As a result of a November 2013 decision by the Court of Appeals, the DOE set the Nuclear Waste Act fee to zero effective May 16, 2014.  By order of the SCPSC, the impact of this action will be considered in future cost of fuel rate adjustments.

Electric - Base Rates

In October 2013, SCE&G received an accounting order from the SCPSC directing it to remove from rate base deferred income tax assets arising from capital expenditures related to the New Units and to accrue carrying costs (recorded as a regulatory asset) on those amounts during periods in which they are not included in rate base.  Such carrying costs are determined at SCE&G’s weighted average long-term borrowing rate. During the three and nine months ended September 30, 2014, $1.6 million and $4.1 million, respectively, of such carrying costs were accrued within other income. SCE&G anticipates that when the New Units are placed in service and accelerated tax deprecation is recognized on them, these deferred income tax assets will decline.  When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized.

SCE&G files an IRP with the SCPSC annually which evaluates future electric generation needs based on several factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G's 2012 IRP identified six coal-fired units that SCE&G has retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. Three of these units had been retired by December 31, 2013. The net carrying value of these retired units is recorded in regulatory assets as unrecovered plant and is being amortized over the units' previously estimated remaining useful lives as approved by the SCPSC. See also Note 1.

SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and net lost margin revenue associated with the DSM Programs, along with an incentive for investing in

13

such programs. SCE&G submits annual filings regarding the DSM Programs, net lost margin revenues, program costs, incentives and net program benefits. The SCPSC approved the following rate increases pursuant to annual DSM Programs filings, which went into effect as indicated:

Year	Effective	Amount
2014	First billing cycle of May	$15.4 million
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million

Other activity related to SCE&G’s DSM Programs is as follows:

• In May 2013 the SCPSC ordered the deferral as a regulatory asset of one-half of net lost margin revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014.

• In April 2014 the SCPSC approved SCE&G’s request to (1) recover one-half of the balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2014 and to recover the remaining balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2015, (2) utilize approximately $17.8 million of the gains from the late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of the net lost margin revenues component of SCE&G’s DSM Programs rider, and (3) apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments to the remaining balance of deferred net lost margin revenues as of April 30, 2014, which had been deferred within regulatory assets resulting from the May 2013 order previously described. 

• In addition, in April 2014 the SCPSC, upon recommendation of the ORS, reduced by 25%, or $6.6 million, the amount of net lost margin revenues SCE&G expects to experience over the 12-month period beginning with the first billing cycle of May 2014, and ordered that the $6.6 million be applied to decrease the amount of program costs deferred for recovery. Actual net lost margin revenues not collected in the current DSM Programs rate rider are subject to true up in the following program year.

Electric – BLRA

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 retail electric rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated:

Year	Action			Amount
2014	2.8	%	Increase	$66.2 million
2013	2.9	%	Increase	$67.2 million
2012	2.3	%	Increase	$52.1 million

Gas

SCE&G

The RSA is designed to reduce the volatility of costs charged to customers by allowing for 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
2014	0.6	%	Decrease	$2.6 million
2013	No change			-
2012	2.1	%	Increase	$7.5 million

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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, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual review conducted for the 12-month period ended July 31, 2013 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during the review period were reasonable and prudent. SCE&G's 2014 annual PGA hearing was held on November 6, 2014 and the SCPSC's ruling is pending.

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 September 2014, in connection with PSNC Energy's 2014 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, 2014.

During the third quarter of 2013, the State of North Carolina passed legislation that changed statutes covering gross receipts, sales and use, excise, franchise and income taxes.  On December 6, 2013, the NCUC issued an order notifying utilities that the incremental revenue requirement impact associated with the change in the level of state income tax expense included in each utility’s cost of service would be deemed to be collected on a provisional basis (subject to refund) beginning January 1, 2014. On May 13, 2014, the NCUC issued an order requiring utilities to adjust rates to reflect changes in the state corporate income tax rate and to file a proposal to refund amounts collected on a provisional basis. Pursuant to the order, PSNC Energy lowered its rates effective July 1, 2014, and notwithstanding a subsequent reversal of the NCUC's order, PSNC Energy expects to refund amounts collected on a provisional basis through the normal operation of the Rider D rate mechanism. At September 30, 2014, these amounts were not material.

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 regulatory liabilities which are summarized in the following tables. Other than unrecovered plant, 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	September 30, 2014		December 31, 2013
Regulatory Assets:
Accumulated deferred income taxes	$	254	$	259
Under-collections - electric fuel adjustment clause	38		18
Environmental remediation costs	40		41
AROs and related funding	378		368
Franchise agreements	27		31
Deferred employee benefit plan costs	222		238
Planned major maintenance	7		—
Deferred losses on interest rate derivatives	318		124
Deferred pollution control costs	36		37
Unrecovered plant	139		145
DSM Programs	53		51
Other	52		48
Total Regulatory Assets	$	1,564	$	1,360

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Regulatory Liabilities:
Accumulated deferred income taxes	$	22	$	24
Asset removal costs	719		695
Storm damage reserve	6		27
Monetization of bankruptcy claim	27		29
Deferred gains on interest rate derivatives	83		181
Planned major maintenance	—		10
Total Regulatory Liabilities	$	857	$	966

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 sites currently or formerly owned by the Company, and are expected to be recovered over periods of up to approximately 26 years.

ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs related to generation, transmission, distribution and other properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 90 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 is recovering these amounts through cost of service rates through 2021.

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, as well as costs deferred pursuant to specific SCPSC regulatory orders. In connection with a December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are being recovered through utility rates over approximately 30 years. In connection with the October 2013 RSA order, approximately $14 million of deferred pension costs for gas operations are being recovered through utility rates over approximately 14 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 and accrues $18.4 million annually for fossil fueled turbine/generation equipment maintenance, and collects and accrues $17.2 million annually for nuclear-related refueling charges.

Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense over periods up to approximately 50 years except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC. Also, in 2014, as discussed at Rate Matters - Electric - Cost of Fuel and Rate Matters - Electric - Base Rates, certain of these deferred amounts were applied to offset under-collected fuel balances and unrecorded net lost margin revenues related to DSM Programs.

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Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at certain coal-fired generating plants pursuant to specific regulatory orders.  Such costs are being recovered through utility rates through 2045.

Unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return.

DSM Programs represent deferred costs associated with such programs.  As a result of an April 2014 SCPSC order, deferred costs are currently being recovered over approximately ten years through an approved rate rider.  See Rate Matters - Electric - Base Rates above for details regarding the 2014 filing with the SCPSC regarding recovery of these deferred costs.

Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 33 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. In 2014, $16.2 million of the reserve was applied to offset incremental storm damage costs. Also, as discussed at Rate Matters - Electric - Base Rates, in April 2014 $5.0 million of the reserve was applied to offset unrecovered net lost margin revenues related to DSM Programs.

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.

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3.COMMON EQUITY

Changes in common equity during the nine months ended September 30, 2014 and 2013 were as follows:

						Accumulated Other Comprehensive Income (Loss)
Millions of dollars	Common Stock		Retained Earnings			Gains (Losses) on Cash Flow Hedges			Deferred Employee Benefit Plans			Total AOCI			Total Common Equity
Balance as of January 1, 2014	$	2,280	$	2,444		$	(52	)	$	(8	)	$	(60	)	$	4,664
Net Income			433												433
Other Comprehensive Income (Loss):
Losses arising during the period						(3		)	—			(3		)	(3		)
Losses/amortization reclassified from AOCI						1			1			2			2
Total Comprehensive Income (Loss)			433			(2		)	1			(1		)	432
Issuance of Common Stock	75														75
Dividends Declared			(223		)										(223		)
Balance as of September 30, 2014	$	2,355	$	2,654		$	(54	)	$	(7	)	$	(61	)	$	4,948
Balance as of January 1, 2013	$	1,983	$	2,257		$	(70	)	$	(16	)	$	(86	)	$	4,154
Net Income			368												368
Other Comprehensive Income:
Gains arising during the period						3			4			7			7
Losses/amortization reclassified from AOCI						7			1			8			8
Total Comprehensive Income			368			10			5			15			383
Issuance of Common Stock	273														273
Dividends Declared			(212		)										(212		)
Balance as of September 30, 2013	$	2,256	$	2,413		$	(60	)	$	(11	)	$	(71	)	$	4,598

Gains and losses on cash flow hedges reclassified during the nine months ended September 30, 2014 resulted in higher interest expense of $5 million and lower cost of gas purchased for resale of $4 million. Such reclassifications during the comparable period in 2013 resulted in higher interest expense of $5 million and higher cost of gas purchased for resale of $2 million.

SCANA had 200 million shares of common stock authorized as of September 30, 2014 and December 31, 2013, of which 142.2 million and 140.7 million were issued and outstanding at September 30, 2014 and December 31, 2013, 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.

4. LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In May 2014, SCE&G issued $300 million of 4.5% first mortgage bonds due June 1, 2064. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

In March 2013, SCE&G entered into a contract for the purchase of nuclear fuel totaling $100 million and payable in 2016.

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In January 2013, JEDA issued at a premium, for the benefit of SCE&G, $39.5 million of 4.00% 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.

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	September 30, 2014			December 31, 2013			September 30, 2014			December 31, 2013			September 30, 2014		December 31, 2013
Lines of credit:
Total committed long-term	$	300		$	300		$	1,400		$	1,400		$	100	$	100
Outstanding commercial paper (270 or fewer days)	$	127		$	125		$	361		$	251		—		—
Weighted average interest rate	0.35		%	0.39		%	0.28		%	0.27		%	—		—
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—		—
Available	$	170		$	172		$	1,039		$	1,149		$	100	$	100

SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million, $1.2 billion (of which $500 million relates to Fuel Company) and $100 million, respectively. In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million. In October 2014, the term of the five-year agreements was extended by one year, such that they expire in October 2019. The three-year agreement expires in October 2016. 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 Company expects to replace the letters of credit in the fourth quarter of 2014.

5.INCOME TAXES

During 2013 the Company amended certain of its tax returns to claim certain tax-defined research and development deductions and credits. In connection with these filings, the Company recorded an unrecognized tax benefit of $3.0 million. During 2014 the Company filed its 2013 tax return and amended additional tax returns to claim certain tax-defined research and development deductions and credits. In connection with these filings, the Company increased its unrecognized tax benefit by $8.2 million (for a total of $11.2 million). If recognized, this tax benefit would affect the Company’s effective tax rate. No other material changes in the status of the Company’s tax positions have occurred through September 30, 2014. These amended returns are now under examination by the IRS.

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  Because no refunds related to the unrecognized tax benefits have yet been received, the Company has not recorded any interest expense or penalties associated with them.

During the third quarter of 2013, the State of North Carolina passed legislation that lowered the state corporate income tax rate from 6.9% to 6.0% in 2014 and 5.0% in 2015.  In connection with this change in tax rates, related state deferred tax

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amounts were remeasured, with the change in their balances being credited to a regulatory liability. The change in income tax rates did not and is not expected to have a material impact on the Company’s financial position, results of operations or cash flows. 

Additionally, during the third quarter of 2013, the IRS issued final regulations regarding the capitalization of certain costs for income tax purposes and re-proposed certain other related regulations (collectively referred to as tangible personal property regulations).  Related IRS revenue procedures were then issued on January 24, 2014. These regulations and procedures did not and are not expected to have a material impact on the Company's financial position, results of operations or cash flows.

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 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 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 under- or over-recovery of gas costs.  These derivative financial instruments are not designated as hedges for accounting purposes.

Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI.  When the hedged transactions affect earnings, 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.  In cases in which 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.

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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.  Except as described in the following paragraph, 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. For the holding company or nonregulated subsidiaries, such amounts are recorded in AOCI.  Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income.

Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are no longer designated as cash flow hedges, and related fair value changes and settlement amounts are recorded as regulatory assets and liabilities. Upon settlement, losses on swaps will be amortized over the lives of related debt issuances, and gains may be applied to under-collected fuel, may be amortized to interest expense or may be applied as otherwise directed by the SCPSC.

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 September 30, 2014
Commodity contracts	6,000,000	10,654,000	3,193,220	19,847,220
Energy management contracts (a)	—	—	38,237,189	38,237,189
Total (a)	6,000,000	10,654,000	41,430,409	58,084,409
As of December 31, 2013
Commodity contracts	6,070,000	6,726,000	2,560,000	15,356,000
Energy management contracts (b)	—	—	27,359,958	27,359,958
Total (b)	6,070,000	6,726,000	29,919,958	42,715,958

(a)  Includes an aggregate 1,199,038 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 348,453 MMBTU related to basis swap contracts in Energy Marketing.

The Company was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $124.4 million at September 30, 2014 and $128.8 million at December 31, 2013. The Company was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.1 billion at September 30, 2014 and $1.3 billion at December 31, 2013.

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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 September 30, 2014
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	4
				Other deferred credits and other liabilities	22
Commodity contracts	Derivative financial instruments	$	1	Derivative financial instruments	3
Total		$	1		$	29
Not designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	102
				Other deferred credits and other liabilities	51
Commodity contracts	Prepayments and other	$	2
Energy management contracts	Prepayments and other	5		Derivative financial instruments	4
	Other deferred debits and other assets	2		Other deferred credits and other liabilities	3
Total		$	9		$	160

As of December 31, 2013
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	5
				Other deferred credits and other liabilities	14
Commodity contracts	Prepayments and other	$	2
Total		$	2		$	19
Not designated as hedging instruments
Interest rate contracts	Prepayments and other	$	13	Derivative financial instruments	$	1
	Other deferred debits and other assets	19
Commodity contracts	Prepayments and other	2
Energy management contracts	Prepayments and other	4		Derivative financial instruments	4
	Other deferred debits and other assets	4		Other deferred credits and other liabilities	4
Total		$	42		$	9

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

Derivatives Designated as Fair Value Hedges

The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented.

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Derivatives in Cash Flow Hedging Relationships

	Gain (Loss) Deferred in Regulatory Accounts						Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)						(Effective Portion)
Millions of dollars	2014			2013		Location	2014			2013
Three Months Ended September 30,
Interest rate contracts	$	(1	)	$	19	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(5	)	$	115	Interest expense	$	(2	)	$	(2	)

	Gain (Loss) Recognized in OCI, net of tax							Gain (Loss) Reclassified from AOCI into Income, net of tax
	(Effective Portion)							(Effective Portion)
Millions of dollars	2014			2013			Location	2014			2013
Three Months Ended September 30,
Interest rate contracts	—			—			Interest expense	$	(2	)	$	(2	)
Commodity contracts	$	(2	)	$	(1	)	Gas purchased for resale	—			—
Total	$	(2	)	$	(1	)		$	(2	)	$	(2	)
Nine Months Ended September 30,
Interest rate contracts	$	(4	)	$	4		Interest expense	$	(5	)	$	(5	)
Commodity contracts	1			(1		)	Gas purchased for resale	4			(2		)
Total	$	(3	)	$	3			$	(1	)	$	(7	)

As of September 30, 2014, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include an insignificant increase to gas cost and approximately $6.3 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of September 30, 2014, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2016.

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 and nine months ended September 30, 2014 and 2013, respectively.

Derivatives not designated as Hedging Instruments
Millions of dollars	Loss Deferred in Regulatory Accounts			Gain Reclassified from Deferred Accounts into Income
Three Months Ended September 30, 2014				Location	Amount
Interest rate contracts	$	(35	)	Other income	$	5
Nine Months Ended September 30, 2014
Interest rate contracts	$	(220	)	Other income	$	60

For the three and nine months ended September 30, 2013, no losses were deferred in regulatory accounts, and no amounts were reclassified from deferred accounts into income. As of September 30, 2014, the Company expects that during the next 12 months reclassifications from other current liabilities and deferred regulatory accounts to earnings arising from derivatives not designated as hedges will include $9.6 million as an increase to other income. The effect of this increase on net income will be entirely offset by net lost margin revenues from DSM Programs as further described in Note 2.

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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. 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 permit the secured party to demand the posting of 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 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 may require the Company to provide collateral upon the occurrence of specific events, primarily credit downgrades.  As of September 30, 2014 and December 31, 2013, the Company has posted $69.0 million and $26.8 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 condensed consolidated balance sheets. Collateral related to noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the condensed consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of September 30, 2014 and December 31, 2013, the Company could have been required to post an additional $117.0 million and $- 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 September 30, 2014 and December 31, 2013 is $187.0 million and $25.2 million, respectively.

In addition, as of September 30, 2014 and December 31, 2013, 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 September 30, 2014 and December 31, 2013, the Company could request $- million and $34.1 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 September 30, 2014 and December 31, 2013 is $- million and $34.1 million, respectively. In addition, at September 30, 2014, the Company could have called on letters of credit in the amount of $5.0 million related to $6.0 million in commodity derivatives that are in a net asset position, compared to letters of credit of $6.0 million related to derivatives of $6.0 million at December 31, 2013, 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 September 30, 2014
Interest rate contracts	—		—			—		—	—	—
Commodity contracts	$	3	$	(1	)	$	2	—	—	$	2
Energy management contracts	7		(1		)	6		—	—	6
Total	$	10	$	(2	)	$	8	—	—	$	8
Balance sheet location	Prepayments and other					$	6
	Other deferred debits and other assets					2
	Total					$	8

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As of December 31, 2013
Interest rate contracts	$	32	—	$	32	$	(1	)	—	$	31
Commodity contracts	4		—	4		—			—	4
Energy management contracts	8		—	8		—			—	8
Total	$	21	—	$	44	$	(1	)	—	$	43
Balance sheet location	Prepayments and other			$	21
	Other deferred debits and other assets			23
	Total			$	44

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 September 30, 2014
Interest rate contracts	$	179	—			$	179	—	$	(63	)	$	116
Commodity contracts	3		$	(1	)	2		—	(1		)	1
Energy management contracts	7		(1		)	6		—	(5		)	1
Total	$	189	$	(2	)	$	187	—	$	(69	)	$	118
Balance sheet location	Derivative financial instruments					$	112
	Other deferred credits and other liabilities					75
	Total					$	187

As of December 31, 2013
Interest rate contracts	$	20	—	$	20	$	(1	)	$	(19	)	—
Energy management contracts	8		—	8		—			(6		)	$	2
Total	$	28	—	$	28	$	(1	)	$	(25	)	$	2
Balance sheet location	Derivative financial instruments			$	10
	Other deferred credits and other liabilities			18
	Total			$	28

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 data.  Fair value measurements, and the level within the fair value hierarchyin which the measurements fall, were as follows:

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	As of September 30, 2014				As of December 31, 2013
Millions of dollars	Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	$	12	—		$	9	—
Interest rate contracts	—		—		—		$	32
Commodity contracts	2		$	1	2		2
Energy management contracts	1		6		1		7
Liabilities:
Interest rate contracts	—		179		—		20
Commodity contracts	—		3		—		—
Energy management contracts	—		10		—		12

There were no Level 3 fair value measurements for either period presented, and 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 September 30, 2014 and December 31, 2013 were as follows:

	September 30, 2014				December 31, 2013
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	5,733.2	$	6,469.6	$	5,449.3	$	5,916.3

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. 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.

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	2014			2013			2014			2013
Three months ended September 30,
Service cost	$	5.0		$	5.1		$	0.9		$	1.2
Interest cost	9.9			9.5			2.8			2.8
Expected return on assets	(16.4		)	(15.1		)	—			—
Prior service cost amortization	1.1			1.5			0.1			0.1
Charge due to curtailment	—			9.9			—			—
Amortization of actuarial losses	0.9			3.5			(0.2		)	0.8
Net periodic benefit cost	$	0.5		$	14.4		$	3.6		$	4.9

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	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2014			2013			2014		2013
Nine months ended September 30,
Service cost	$	15.0		$	16.9		$	3.4	$	4.4
Interest cost	30.3			28.4			9.0		8.3
Expected return on assets	(50.0		)	(45.8		)	—		—
Prior service cost amortization	3.1			4.9			0.3		0.5
Charge due to curtailment	—			9.9			—		—
Transition obligation amortization	—			—			—		0.3
Amortization of actuarial losses	3.5			14.4			—		2.5
Net periodic benefit cost	$	1.9		$	28.7		$	12.7	$	16.0

No significant contribution to the pension trust is expected for the foreseeable future, nor is a limitation on benefit payments expected to apply. SCE&G recovers current pension costs through either a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations. Certain pension costs arising prior to 2013 were deferred for future recovery under regulatory orders as discussed 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 SCE&G's nuclear power plant. Price-Anderson provides funds up to $13.6 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 $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 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 $84.8 million per incident, but not more than $12.6 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 insurance 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 resulting from an event of nuclear origin. 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 $43.5 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, 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.

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.  

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SCE&G's current ownership share in the New Units is 55%. Under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, will acquire an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and will acquire the final 2% no later than the second anniversary of such commercial operation date. Under the terms of the agreement SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost of the percentage conveyed as of the date of conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction will not affect the payment obligations between the parties during construction for the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA.

Under the BLRA, the SCPSC has approved, among other things, the milestone schedule and capital costs estimates schedule for the New Units. The effect of this approval is that it constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. The BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Such annual rate changes are described in Note 2.

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 have impacted the project budget and schedule. SCE&G expects to resolve all disputes through both the informal and formal procedures and anticipates that any costs that arise through such dispute resolution processes, as well as other costs identified from time to time, will be recoverable through rates.

In November 2012, the SCPSC approved a petition by SCE&G under the BLRA for an updated milestone schedule and additional updated capital costs for the New Units. In addition, the SCPSC 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 known claims by the Consortium 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. Immediately thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its order, and 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, contending that the SCPSC erred in granting approval of the updated capital costs for the New Units. On October 22, 2014, the South Carolina Supreme Court affirmed the SCPSC's order.

The substantial completion dates currently approved by the SCPSC for Units 2 and 3 are March 15, 2017 and May 15, 2018. The SCPSC has also approved an 18-month contingency period beyond each of these dates. As of September 30, 2014, SCE&G's 55% share of the estimated cash outlays (future value, excluding AFC) totaled approximately $5.5 billion for plant and related transmission infrastructure costs, based on historical one-year and five-year escalation rates as required by the SCPSC. As of September 30, 2014, and based on the updated milestone schedule and capital costs schedule approved by the SCPSC in November 2012 (see above), SCE&G estimated such cost will be approximately $500 million for the additional 5% interest being acquired from Santee Cooper.

Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule for fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules have been and remain focus areas of the Consortium, including sub-modules for module CA20, which is part of the auxiliary building, and CA01, which houses components inside the containment vessel. Modules CA20 and CA01, as well as shield building modules, are considered critical path items for both New Units. CA20 was placed on the nuclear island of Unit 2 in May 2014. The delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow it to be ready for placement on the nuclear island of Unit 2 during the first half of 2015.

During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the schedules and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and design resource allocations, procurement, construction work crew efficiencies, and other items. The result will be a revised fully integrated project schedule with timing of specific construction activities along with detailed information on budget, cost and cash flow requirements. While this detailed re-baselining of construction schedules has not been completed, in August 2014, SCE&G received preliminary information in which the Consortium has indicated that the substantial completion of Unit

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2 is expected to occur in late 2018 or the first half of 2019 and that the substantial completion of Unit 3 may be approximately 12 months later. These expected substantial completion dates do not reflect all efforts that may be possible to mitigate delay, nor has SCE&G accepted this new schedule.

Also in August 2014, the IRS notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. To the extent that production tax credits are realized, their benefits are expected to be provided to SCE&G's electric customers.

The Consortium has also provided preliminary cost estimates for Units 2 and 3 principally related to delays for non-firm and non-fixed scopes of work to achieve the late 2018 substantial completion date for Unit 2 and a substantial completion date for Unit 3 approximately 12 months later. SCE&G's 55% portion of this preliminary estimate is approximately $660 million. This figure is presented in 2007 dollars and would be subject to escalation. This figure also excludes any owner's cost amounts associated with the delays, which amounts could be significant. Further, this figure does not reflect consideration of the liquidated damages provisions of the EPC Contract which would partly mitigate any such delay-related costs. The Consortium's preliminary schedule and the cost estimate information have not been accepted by SCE&G and are under review. It is anticipated that further study, evaluation and negotiations will occur. SCE&G plans to reevaluate and reschedule its owners cost estimates and cash flow requirements in light of that new schedule when it is finalized. SCE&G anticipates that the revised schedule and cost estimate will be finalized sometime in 2015.

The milestone schedule approved by the SCPSC in November 2012 provides for 146 milestone dates, which are each subject to an 18-month schedule contingency. As of October 31, 2014, 100 milestones have been completed. The completion dates for two of the remaining milestones have been extended beyond their 18-month contingency periods, and it is anticipated that the completion dates for a number of the other remaining milestone dates will also extend beyond their contingency periods. Upon completion of the re-baselining and the finalization of the revised schedule and cost estimate at completion, SCE&G, as provided for under the BLRA, expects to petition the SCPSC for an order to update the BLRA milestone schedule and capital costs estimates schedule. The BLRA provides that the SCPSC shall grant the petition for modification if the record justifies a finding that the change is not the result of imprudence by SCE&G.

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.  SCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the construction and operation of the New Units, and prepared and submitted an integrated response plan for the New Units to the NRC in August 2013. SCE&G cannot predict what additional regulatory or other outcomes may be implemented, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New Units.

Environmental

As part of the President's Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA was directed to issue a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The rule became final on January 8, 2014 and requires 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-fired plants can be constructed without carbon capture and sequestration capabilities. The Company is evaluating the final rule, but does not plan to construct new coal-fired units in the foreseeable future.

The Memorandum also directed the EPA to issue standards, regulations, or guidelines for existing units. On June 2, 2014, the EPA released the Clean Power Plan, a proposal to regulate carbon dioxide emissions from existing units. The proposed rule includes state-specific goals for carbon dioxide emissions, as well as guidelines for states to follow in developing SIPs to achieve those goals. The Company is evaluating the proposed rule which may be revised before it becomes final in June 2015. As currently proposed, states will have from one to three years from the date of any final rule to issue SIPs that will ultimately define the specific compliance methodology that will be applied to existing units in that state. The Company expects that any costs incurred to comply with such requirements will be recoverable through rates.

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In 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states 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 Court of Appeals 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. On April 29, 2014, the U. S. Supreme Court reversed the judgment of the Court of Appeals, and CSAPR was remanded to the Court of Appeals for further proceedings consistent with the U. S. Supreme Court opinion. On October 23, 2014, the Court of Appeals granted EPA's June 26, 2014 motion to lift the stay of the CSAPR. EPA's motion asked the court to postpone the CSAPR compliance deadlines by three years, so that CSAPR's Phase 1 emission budgets will apply starting in 2015, and CSAPR's Phase 2 emission budgets will apply in 2017 and subsequent years. Air quality control installations that SCE&G and GENCO have already completed have allowed the Company to comply with the reinstated CAIR and will also allow it to comply with CSAPR. 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 CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule was published in the Federal Register on June 7, 2013, and is expected to be finalized September 30, 2015. The EPA expects compliance within a three to six year time frame as NPDES permits are renewed.

On August 15, 2014, the EPA finalized a rule (effective October 14, 2014) that modifies requirements for existing cooling water intake structures. The Company is conducting studies and is developing or implementing compliance plans for this rule. Congress is also expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones. These provisions, if passed, could have a material impact on the financial condition, results of operations and cash flows of the Company. The Company believes that any additional costs imposed by such regulations, including compliance therewith, would be recoverable through rates.

In response to a federal court order to establish a definite timeline for a CCR rule and subsequent obligation via consent decree, the EPA committed to issue new federal regulations affecting the management and disposal of CCRs, such as ash, by December 19, 2014. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities such as SCE&G and GENCO. While the Company cannot predict how extensive the regulations will be, the Company believes that any additional costs imposed by such regulations would be recoverable through rates.

The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998. The Nuclear Waste Act also imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. To date, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017, and is constructing a dry cask storage facility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1. SCE&G may evaluate other technology as it becomes available. See also Note 2.

The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. In addition, the states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts

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estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates.

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 through 2017 and will cost an additional $19.5 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 September 30, 2014, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $35.9 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 potentially responsible parties.  PSNC Energy has recorded a liability and associated regulatory asset of approximately $1.1 million, the estimated remaining liability at September 30, 2014. PSNC Energy expects to recover through rates any cost allocable to PSNC Energy arising from the remediation of these sites.

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.

Millions of dollars	External Revenue			Intersegment Revenue			Operating Income			Net Income
Three Months Ended September 30, 2014
Electric Operations	$	739		$	1		$	275		n/a
Gas Distribution	127			—			(6		)	n/a
Retail Gas Marketing	68			—			n/a			$	(3	)
Energy Marketing	182			47			n/a			(2		)
All Other	9			103			7			(5		)
Adjustments/Eliminations	(4		)	(151		)	(7		)	154
Consolidated Total	$	1,121		$	—		$	269		$	144

Nine Months Ended September 30, 2014
Electric Operations	$	2,027		$	5		$	616	n/a
Gas Distribution	728			—			98		n/a
Retail Gas Marketing	367			—			n/a		$	16
Energy Marketing	602			154			n/a		5
All Other	27			317			21		(3		)
Adjustments/Eliminations	(15		)	(476		)	37		415
Consolidated Total	$	3,736		$	—		$	772	$	433

Three Months Ended September 30, 2013
Electric Operations	$	704		$	2		$	257		n/a
Gas Distribution	123			—			(6		)	n/a
Retail Gas Marketing	67			—			n/a			$	(2	)
Energy Marketing	152			44			n/a			1
All Other	11			95			8			(3		)
Adjustments/Eliminations	(6		)	(141		)	(4		)	135
Consolidated Total	$	1,051		$	—		$	255		$	131

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Nine Months Ended September 30, 2013
Electric Operations	$	1,898		$	6		$	588	n/a
Gas Distribution	657			—			94		n/a
Retail Gas Marketing	325			—			n/a		$	16
Energy Marketing	488			133			n/a		5
All Other	30			303			22		(2		)
Adjustments/Eliminations	(20		)	(442		)	34		349
Consolidated Total	$	3,378		$	—		$	738	$	368

	September 30,		December 31,
Segment Assets	2014		2013
Electric Operations	$	9,898	$	9,488
Gas Distribution	2,365		2,340
Retail Gas Marketing	121		172
Energy Marketing	110		133
All Other	1,333		1,378
Adjustments/Eliminations	2,044		1,653
Consolidated Total	$	15,871	$	15,164

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

OF OPERATIONS

SCANA CORPORATION

The following discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations appearing in SCANA’s Annual Report on Form 10-K for the year ended December 31, 2013.

RESULTS OF OPERATIONS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2014

AS COMPARED TO THE CORRESPONDING PERIODS IN 2013

Earnings Per Share

Earnings per share was as follows:

	Third Quarter				Year to Date
	2014		2013		2014		2013
Basic earnings per share	$	1.01	$	0.94	$	3.06	$	2.67
Diluted earnings per share	$	1.01	$	0.94	$	3.06	$	2.66

Third Quarter and Year to Date

Basic earnings per share increased primarily due to higher electric margins (resulting primarily from the effects of weather and base rate increases under the BLRA) and higher gas margins and other income. These increases were partially offset by higher operation and maintenance expenses, higher property taxes, higher depreciation expense, higher interest cost, and dilution from additional shares outstanding, as further discussed below.

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 2014:

Declaration Date	Dividend Per Share	Record Date	Payment Date
February 20, 2014	$0.5250	March 10, 2014	April 1, 2014
April 24, 2014	$0.5250	June 10, 2014	July 1, 2014
July 31, 2014	$0.5250	September 10, 2014	October 1, 2014
October 30, 2014	$0.5250	December 10, 2014	January 1, 2015

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:

33

	Third Quarter						Year to Date
Millions of dollars	2014		Change		2013		2014		Change		2013
Operating revenues	$	740.4	4.9	%	$	706.0	$	2,032.7	6.8	%	$	1,903.2
Less:  Fuel used in generation	213.3		7.9	%	197.6		639.9		11.4	%	574.5
Purchased power	13.1		(30.7	)%	18.9		54.4		56.8	%	34.7
Margin	$	514.0	5.0	%	$	489.5	$	1,338.4	3.4	%	$	1,294.0

Third Quarter

Electric margin increased due to the effects of weather of $12.9 million, base rate increases under the BLRA of $15.6 million and customer growth of $4.0 million. These margin increases were partially offset by $4.4 million of downward adjustments to electric revenues pursuant to the SCPSC orders related to SCE&G's DSM Programs. These adjustments to electric revenues were fully offset by the recognition, within other income, of gains realized upon the late 2013 settlement of certain derivative interest rate contracts which had been deferred in regulatory accounts.

Year to Date

Electric margin increased due to the effects of weather of $46.4 million, base rate increases under the BLRA of $40.4 million and customer growth of $11.7 million. These margin increases were partially offset by $64.6 million of downward adjustments to electric revenues pursuant to the SCPSC orders related to fuel cost recovery and SCE&G's DSM Programs. These adjustments to electric revenues were fully offset by the recognition, within other income, of gains realized upon the late 2013 settlement of certain derivative interest rate contracts and the application, as a reduction to operation and maintenance expenses, of a portion of SCE&G's storm damage reserve, both of which had been deferred in regulatory accounts.

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

	Third Quarter				Year to Date
Classification	2014	Change		2013	2014	Change		2013
Residential	2,315	4.5	%	2,216	6,370	8.7	%	5,858
Commercial	2,100	1.3	%	2,073	5,676	2.8	%	5,520
Industrial	1,668	5.3	%	1,584	4,662	3.5	%	4,505
Other	170	3.7	%	164	459	3.8	%	442
Total Retail Sales	6,253	3.6	%	6,037	17,167	5.2	%	16,325
Wholesale	258	5.3	%	245	737	0.1	%	736
Total Sales	6,511	3.6	%	6,282	17,904	4.9	%	17,061

Third Quarter and Year to Date

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

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:

	Third Quarter						Year to Date
Millions of dollars	2014		Change		2013		2014		Change		2013
Operating revenues	$	127.9	3.1	%	$	124.1	$	729.5	10.9	%	$	658.0
Less:  Gas purchased for resale	69.4		2.5	%	67.7		437.6		16.4	%	375.9
Margin	$	58.5	3.7	%	$	56.4	$	291.9	3.5	%	$	282.1

Third Quarter

Margin increased primarily due to residential and commercial customer growth.

34

Year to Date

Margin increased primarily due to residential and commercial customer growth of $6.3 million and increased average usage at SCE&G of $2.5 million. SCE&G's WNA and PSNC Energy's CUT mitigate weather-related fluctuations in margin but have no impact on volumes.

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

	Third Quarter				Year to Date
Classification (in thousands)	2014	Change		2013	2014	Change		2013
Residential	2,149	7.7	%	1,995	31,165	14.4	%	27,235
Commercial	4,396	6.5	%	4,129	21,808	10.3	%	19,774
Industrial	4,749	(7.6	)%	5,141	15,128	(9.6	)%	16,740
Transportation	11,341	9.9	%	10,316	32,912	5.1	%	31,303
Total	22,635	4.9	%	21,581	101,013	6.3	%	95,052

Third Quarter

Residential and commercial sales volumes increased primarily due to customer growth. Industrial sales volumes decreased due to a customer switching to an alternative fuel source. Transportation sales volume increased primarily from natural gas-fired electric generation.

Year to Date

Residential and commercial sales volumes increased primarily due to the effects of weather, customer growth and increased average usage at SCE&G. Industrial sales volumes decreased due to weather-related curtailments and a customer switching to an alternative fuel source. Transportation sales volume increased primarily from natural gas-fired electric generation.

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 (loss) were as follows:

	Third Quarter								Year to Date
Millions of dollars	2014			Change		2013			2014		Change		2013
Operating revenues	$	68.4		2.4	%	$	66.8		$	367.4	13.1	%	$	324.9
Net income (loss)	(2.8		)	(26.3	)%	(3.8		)	16.4		5.1	%	15.6

Third Quarter and Year to Date

Operating revenues increased in 2014 due to increased demand, primarily in the first quarter, and customer growth. Net income in 2014 was impacted by higher revenues related to the increased demand primarily from the colder than normal weather in the first quarter, partially offset by higher costs including commodity costs and bad debt expense.

35

Energy Marketing

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

	Third Quarter							Year to Date
Millions of dollars	2014			Change		2013		2014		Change		2013
Operating revenues	$	228.8		16.9	%	$	195.7	$	756.1	21.7	%	$	621.2
Net income (loss)	(2.6		)	*		1.8		5.1		(7.3	)%	5.5

 * Greater than 100%

Third Quarter

Operating revenues increased due to higher market prices. Net income in 2014 was impacted by higher commodity and transportation costs. 

Year to Date

Operating revenues increased due to higher market prices and incremental sales primarily in the first quarter, offset in net income by higher commodity and transportation costs in the third quarter. 

Other Operating Expenses

Other operating expenses were as follows:

	Third Quarter						Year to Date
Millions of dollars	2014		Change		2013		2014		Change		2013
Other operation and maintenance	$	169.2	1.6	%	$	166.6	$	522.9	1.8	%	$	513.5
Depreciation and amortization	95.9		1.4	%	94.6		286.1		1.3	%	282.4
Other taxes	58.2		7.0	%	54.4		173.8		6.2	%	163.7

 Third Quarter

Other operation and maintenance expenses increased primarily due to higher electric operating expenses of $2.0 million and other general expenses of $2.1 million. These increases were partially offset by lower labor costs of $1.9 million. Depreciation and amortization expense increased due to net plant additions. Other taxes increased primarily due to higher property taxes.

Year to Date

Other operation and maintenance expenses increased primarily due to higher electric operating expenses of $1.8 million, DSM Programs cost amortization of $1.8 million, storm expenses of $1.3 million and other general expenses of $1.6 million. Depreciation and amortization expense increased 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.  Other income increased primarily due to the recognition of $59.6 million of gains realized upon the late 2013 settlement of certain interest rate derivative contracts previously recorded as regulatory liabilities pursuant to SCPSC orders previously discussed. Such gain recognition was fully offset by downward adjustments to revenues reflected within electric margin and had no effect on net income.

36

Interest Expense

     Interest charges increased primarily due to increased borrowings.

Income Taxes

Income taxes increased primarily due to higher income before taxes.

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its 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 nine and 12 months ended September 30, 2014 was 3.58 and 3.44, respectively.

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 Company expects to replace the letters of credit in the fourth quarter of 2014.

At September 30, 2014, the Company had net available liquidity of approximately $1.4 billion, comprised of cash on hand and available amounts under lines of credit. The credit agreements total an aggregate of $1.8 billion, of which $200 million is scheduled to expire in October 2016 and the terms of the other credit agreements have been extended and are scheduled to expire in October 2019. 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 19 years and bears an average interest cost of 5.7%.  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.

In October 2014, SCE&G's authority from FERC to issue short-term indebtedness and to assume liabilities as a guarantor (pursuant to Section 204 of the Federal Power Act) was renewed. 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. In October 2014, GENCO obtained FERC authority to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2016.

SCANA issued approximately $76 million of common stock during the nine months ended September 30, 2014 through various compensation and dividend reinvestment plans.  Similar issuances may occur in future periods. In March 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 million.

SCE&G's current preliminary estimates of its capital expenditures for new nuclear construction (including transmission) for 2014 through 2016, which are subject to continuing review and adjustment, are $806 million in 2014, $916 million in 2015, and $693 million in 2016.

For additional information, see Note 4 to the consolidated financial statements.

OTHER MATTERS

In June 2014, the Distributed Energy Resource Act became law in South Carolina.  Among other things, this law (i) authorizes SCE&G, at its discretion, to implement a distributed energy resource program and recover the reasonable and prudent costs incurred in implementing such a program, (ii) permits non-utilities and utilities to lease renewable electric generation facilities to homeowners and businesses, and (iii) requires the SCPSC to establish a net energy metering rate methodology.  SCE&G is actively participating, along with numerous other stakeholders, in the SCPSC’s net energy metering

37

proceeding; a hearing in this matter has been set for February 3, 2015.  SCE&G is evaluating its options under the law for implementing a distributed energy program.

As Georgia's regulated provider, SCANA Energy provides service to low-income customers and customers unable to obtain or maintain natural gas service from other marketers at rates approved by the GPSC, and SCANA Energy receives funding from the Universal Service Fund to offset some of the bad debt associated with the low-income group. SCANA Energy's current term as the regulated provider is scheduled to end on August 31, 2015. The GPSC will accept bids from energy marketers, including SCANA Energy, to serve as the regulated provider for a two-year period ending August 31, 2017. The GPSC is expected to make its decision in the first quarter of 2015.

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 - Interest rates on substantially all of the Company's outstanding long-term debt 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. The Company uses various financial instruments to manage interest rate risk on anticipated debt issuances. Changes in the fair value of these instruments during the nine months ended September 30, 2014 have resulted in the recording of significant derivative financial instrument liabilities and a corresponding increase in deferred losses on interest rate derivatives within regulatory assets.

For further discussion of changes in long-term debt and interest rate derivatives, including changes in the Company's market risk exposures relative to interest rate risk, see ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – LIQUIDITY AND CAPITAL RESOURCES and also Notes 2, 4, 6 and 7 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.  See Note 6 and 7 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.

	Expected Maturity			Expected Maturity
Futures - Long	2014	2015	Options Purchased Call - Long	2014	2015
Settlement Price (a)	4.16	4.08	Strike Price (a)	4.08	4.30
Contract Amount (b)	7.0	19.4	Contract Amount (b)	8.8	17.3
Fair Value (b)	7.1	19.7	Fair Value (b)	0.5	1.2
(a)  Weighted average, in dollars
(b)  Millions of dollars

38

	Expected Maturity
Swaps	2014	2015	2016	2017	2018
Commodity Swaps:
Pay fixed/receive variable (b)	24.5	62.3	16.0	5.7	3.6
Average pay rate (a)	4.3854	4.4306	4.5148	4.2428	4.2421
Average received rate (a)	4.1607	4.0833	4.0933	4.2253	4.3188
Fair value (b)	23.3	57.4	14.5	5.7	3.6
Pay variable/receive fixed (b)	11.3	42.5	13.0	5.6	3.6
Average pay rate (a)	4.1562	4.0335	4.0860	4.2235	4.3188
Average received rate (a)	4.2570	4.3376	4.5556	4.2507	4.2471
Fair value (b)	11.5	45.7	14.5	5.7	3.6
Basis Swaps:
Pay variable/receive variable (b)	0.6	2.0	1.3	1.1	—
Average pay rate (a)	4.1925	4.1464	4.1619	4.2822	—
Average received rate (a)	4.1642	4.1278	4.1665	4.2873	—
Fair value (b)	0.6	1.9	1.3	1.1	—
(a) Weighted average, in dollars
(b) Millions of dollars

ITEM 4. CONTROLS AND PROCEDURES

As of September 30, 2014, 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 September 30, 2014, 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 September 30, 2014 that has materially affected or is reasonably likely to materially affect SCANA’s internal control over financial reporting.

39

SOUTH CAROLINA ELECTRIC & GAS COMPANY

FINANCIAL SECTION

40

ITEM 1.     FINANCIAL STATEMENTS

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

Millions of dollars	September 30, 2014			December 31, 2013
Assets
Utility Plant In Service	$	10,554		$	10,378
Accumulated Depreciation and Amortization	(3,618		)	(3,499		)
Construction Work in Progress	3,143			2,682
Plant to be Retired, Net	167			177
Nuclear Fuel, Net of Accumulated Amortization	282			310
Utility Plant, Net ($687 and $720 related to VIEs)	10,528			10,048
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	70			69
Assets held in trust, net-nuclear decommissioning	109			101
Other investments	2			3
Nonutility Property and Investments, Net	181			173
Current Assets:
Cash and cash equivalents	42			92
Receivables, net of allowance for uncollectible accounts of $4 and $3	511			486
Affiliated receivables	27			19
Inventories (at average cost):
Fuel and gas supply	127			132
Materials and supplies	128			120
Prepayments and other	104			80
Total Current Assets ($124 and $147 related to VIEs)	939			929
Deferred Debits and Other Assets:
Pension asset	103			96
Regulatory assets	1,506			1,303
Other	142			151
Total Deferred Debits and Other Assets ($43 and $35 related to VIEs)	1,751			1,550
Total	$	13,399		$	12,700

See Notes to Condensed Consolidated Financial Statements.

41

Millions of dollars	September 30, 2014			December 31, 2013
Capitalization and Liabilities
Common Stock - no par value, 40.3 million shares outstanding for all periods presented	$	2,561		$	2,479
Retained Earnings	2,078			1,896
Accumulated Other Comprehensive Loss	(3		)	(3		)
Total Common Equity	4,636			4,372
Noncontrolling Interest	121			117
Total Equity	4,757			4,489
Long-Term Debt, net	4,298			4,007
Total Capitalization	9,055			8,496
Current Liabilities:
Short-term borrowings	361			251
Current portion of long-term debt	46			48
Accounts payable	223			241
Affiliated payables	116			117
Customer deposits and customer prepayments	58			56
Taxes accrued	153			223
Interest accrued	58			64
Dividends declared	69			62
Derivative financial instruments	104			1
Other	58			71
Total Current Liabilities	1,246			1,134
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,585			1,509
Deferred investment tax credits	29			32
Asset retirement obligations	562			547
Postretirement benefits	169			173
Regulatory liabilities	615			732
Other	138			77
Total Deferred Credits and Other Liabilities	3,098			3,070
Commitments and Contingencies (Note 9)	—			—
Total	$	13,399		$	12,700

See Notes to Condensed Consolidated Financial Statements.

42

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited) 

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Millions of dollars	2014			2013			2014			2013
Operating Revenues:
Electric	$	740		$	706		$	2,032		$	1,903
Gas	72			70			337			297
Total Operating Revenues	812			776			2,369			2,200
Operating Expenses:
Fuel used in electric generation	213			197			640			575
Purchased power	13			19			54			34
Gas purchased for resale	46			45			210			177
Other operation and maintenance	136			132			415			406
Depreciation and amortization	79			78			236			234
Other taxes	53			50			158			149
Total Operating Expenses	540			521			1,713			1,575
Operating Income	272			255			656			625
Other Revenue (Expense):
Other revenue	9			—			71			—
Other expense	(7		)	(4		)	(19		)	(11		)
Interest charges, net of allowance for borrowed funds used during construction of $5, $4, $11 and $9	(57		)	(54		)	(169		)	(163		)
Allowance for equity funds used during construction	10			8			22			18
Total Other Revenue (Expense)	(45		)	(50		)	(95		)	(156		)
Income Before Income Tax Expense	227			205			561			469
Income Tax Expense	70			66			178			150
Net Income	157			139			383			319
Net Income Attributable to Noncontrolling Interest	(3		)	(3		)	(9		)	(8		)
Earnings Available to Common Shareholder	$	154		$	136		$	374		$	311
Dividends Declared on Common Stock	$	69		$	67		$	197		$	195

See Notes to Condensed Consolidated Financial Statements.

43

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
Millions of dollars	2014			2013			2014			2013
Net Income	$	157		$	139		$	383		$	319
Other Comprehensive Income, net of tax:
Employee benefit plan remeasurement and curtailment gains arising during the period, net of tax of $-,$-, $-, and $-	—			1			—			1
Total Comprehensive Income	157			140			383			320
Comprehensive income attributable to noncontrolling interest	(3		)	(3		)	(9		)	(8		)
Comprehensive income available to common shareholder	$	154		$	137		$	374		$	312

See Notes to Condensed Consolidated Financial Statements.

44

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
Millions of dollars	2014			2013
Cash Flows From Operating Activities:
Net income	$	383		$	319
Adjustments to reconcile net income to net cash provided from operating activities:
Losses from equity method investments	4			—
Deferred income taxes, net	76			49
Depreciation and amortization	236			237
Amortization of nuclear fuel	31			42
Allowance for equity funds used during construction	(22		)	(18		)
Carrying cost recovery	(7		)	—
Changes in certain assets and liabilities:
Receivables	(34		)	(58		)
Inventories	(36		)	5
Prepayments and other	—			(51		)
Pension and other post retirement benefits	(12		)	(117		)
Regulatory assets	(170		)	129
Regulatory liabilities	(130		)	80
Accounts payable	11			(7		)
Taxes accrued	(70		)	7
Interest accrued	(6		)	(10		)
Other assets	3			(30		)
Other liabilities	167			(3		)
Net Cash Provided From Operating Activities	424			574
Cash Flows From Investing Activities:
Property additions and construction expenditures	(678		)	(794		)
Proceeds from investments (including derivative collateral posted)	163			139
Purchase of investments (including derivative collateral posted)	(202		)	(112		)
Proceeds from interest rate contract settlement	—			43
Payments upon interest rate contract settlement	(34		)	(49		)
Net Cash Used For Investing Activities	(751		)	(773		)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	294			451
Repayment of long-term debt	(12		)	(248		)
Dividends	(190		)	(174		)
Contributions from parent	82			285
Short-term borrowings –affiliate, net	(7		)	(10		)
Short-term borrowings, net	110			(139		)
Net Cash Provided From Financing Activities	277			165
Net Decrease In Cash and Cash Equivalents	(50		)	(34		)
Cash and Cash Equivalents, January 1	92			51
Cash and Cash Equivalents, September 30	$	42		$	17
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $11 and $9)	$	162		$	160
– Income taxes	143			67
Noncash Investing and Financing Activities:
Accrued construction expenditures	94			89
Capital leases	4			3
Nuclear fuel purchase	—			98

See Notes to Condensed Consolidated Financial Statements.

45

SOUTH CAROLINA ELECTRIC & GAS COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the Three and Nine Months Ended September 30, 2014 and 2013

(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, 2013.  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 Entities

SCE&G has determined that it is the primary beneficiary of 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 $502 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

In 2012 SCE&G identified six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. Three of these units had been retired by December 31, 2013, and their net carrying value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units is identified as Plant to be Retired, Net in the condensed 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 use and in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC.

New Accounting Matter

In May 2014, the Financial Accounting Standards Board issued new accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. Consolidated SCE&G will be required to adopt the new guidance in the first quarter of 2017, and early adoption is not permitted.  Consolidated SCE&G has not determined the impact this guidance will have on its results of operations, cash flows or financial position.

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2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric - Cost of Fuel

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 connection with its annual review of base rates for fuel costs, and by order dated April 30, 2013, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC in which SCE&G agreed to reduce its environmental fuel cost component effective with the first billing cycle of May 2013. The order also provided for the accrual of certain debt-related carrying costs on a portion of SCE&G's under-collected balance of fuel costs and approved SCE&G's total fuel cost component.

By order dated April 29, 2014, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC in which SCE&G agreed to increase its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014.  The SCPSC's order also provided for, among other things, the application of approximately $46 million in deferred gains from the late 2013 settlement of certain interest rate swaps, previously recorded as regulatory liabilities, to reduce the under-collected balance of fuel costs in April 2014 and the accrual of certain debt-related carrying costs on its under-collected balance of base fuel costs during the period May 1, 2014 through April 30, 2015. 

The increase to the base fuel cost component was offset by a reduction in SCE&G’s rate rider related to pension costs, which was approved by the SCPSC in March 2014. The reduction was requested by SCE&G as a result of lower net periodic benefit costs in 2014. See also Note 8.

The cost of fuel includes amounts paid by SCE&G pursuant to the Nuclear Waste Act for the disposal of spent nuclear fuel.  As a result of a November 2013 decision by the Court of Appeals, the DOE set the Nuclear Waste Act fee to zero effective May 16, 2014.  By order of the SCPSC, the impact of this action will be considered in future cost of fuel rate adjustments.

Electric - Base Rates

In October 2013, SCE&G received an accounting order from the SCPSC directing it to remove from rate base deferred income tax assets arising from capital expenditures related to the New Units and to accrue carrying costs (recorded as a regulatory asset) on those amounts during periods in which they are not included in rate base.  Such carrying costs are determined at SCE&G’s weighted average long-term borrowing rate. During the three and nine months ended September 30, 2014, $1.6 million and $4.1 million, respectively, of such carrying costs were accrued within other income. SCE&G anticipates that when the New Units are placed in service and accelerated tax deprecation is recognized on them, these deferred income tax assets will decline.  When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized.

SCE&G files an IRP with the SCPSC annually which evaluates future electric generation needs based on several factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G's 2012 IRP identified six coal-fired units that SCE&G has retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. Three of these units had been retired by December 31, 2013. The net carrying value of these retired units is recorded in regulatory assets as unrecovered plant and is being amortized over the units' previously estimated remaining useful lives as approved by the SCPSC. See also Note 1.

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

Year	Effective	Amount
2014	First billing cycle of May	$15.4 million
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million

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Other activity related to SCE&G’s DSM Programs is as follows:

• In May 2013 the SCPSC ordered the deferral as a regulatory asset of one-half of net lost margin revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014.

• In April 2014 the SCPSC approved SCE&G’s request to (1) recover one-half of the balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2014 and to recover the remaining balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2015, (2) utilize approximately $17.8 million of the gains from the late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of the net lost margin revenues component of SCE&G’s DSM Programs rider, and (3) apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments, to the remaining balance of deferred net lost margin revenues as of April 30, 2014, which had been deferred within regulatory assets resulting from the May 2013 order previously described. 

• In addition, in April 2014 the SCPSC, upon recommendation of the ORS, reduced by 25%, or $6.6 million, the amount of net lost margin revenues SCE&G expects to experience over the 12-month period beginning with the first billing cycle of May 2014, and ordered that the $6.6 million be applied to decrease the amount of program costs deferred for recovery. Actual net lost margin revenues not collected in the current DSM Programs rate rider are subject to true up in the following program year.

Electric – BLRA

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 retail electric rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated:

Year	Action			Amount
2014	2.8	%	Increase	$66.2 million
2013	2.9	%	Increase	$67.2 million
2012	2.3	%	Increase	$52.1 million

Gas

The RSA is designed to reduce the volatility of costs charged to customers by allowing for 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
2014	0.6	%	Decrease	$2.6 million
2013	No change			-
2012	2.1	%	Increase	$7.5 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, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual review conducted for the 12-month period ended July 31, 2013 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during the review period were reasonable and prudent. SCE&G's 2014 annual PGA hearing was held on November 6, 2014 and the SCPSC's ruling is pending.

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.  Other than unrecovered plant, 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.

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Millions of dollars	September 30, 2014		December 31, 2013
Regulatory Assets:
Accumulated deferred income taxes	$	250	$	256
Under collections – electric fuel adjustment clause	38		18
Environmental remediation costs	36		37
AROs and related funding	359		350
Franchise agreements	27		31
Deferred employee benefit plan costs	201		215
Planned major maintenance	7		—
Deferred losses on interest rate derivatives	318		124
Deferred pollution control costs	36		37
Unrecovered plant	139		145
DSM Programs	53		51
Other	42		39
Total Regulatory Assets	$	1,506	$	1,303

Regulatory Liabilities:
Accumulated deferred income taxes	$	17	$	19
Asset removal costs	509		495
Storm damage reserve	6		27
Deferred gains on interest rate derivatives	83		181
Planned major maintenance	—		10
Total Regulatory Liabilities	$	615	$	732

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 sites currently or formerly owned by SCE&G and are expected to be recovered over periods of up to approximately 26 years.

ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs related to generation, distribution and other properties.  These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 90 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 is recovering these amounts through cost of service rates through 2021.

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, as well as costs deferred pursuant to specific SCPSC regulatory orders. In connection with a December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are being recovered through utility rates over approximately 30 years. In connection with the October 2013 RSA order, approximately $14 million of deferred pension costs for gas operations are being recovered through utility rates over approximately 14 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 approximately 12 years.

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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 and accrues $18.4 million annually for fossil fueled turbine/generation equipment maintenance and collects and accrues $17.2 million annually for nuclear-related refueling charges.

Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense over periods up to approximately 50 years except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC. Also, in 2014, as discussed at Rate Matters - Electric - Cost of Fuel and Rate Matters - Electric - Base Rates, certain of these deferred amounts were applied to offset under-collected fuel balances and unrecorded net lost margin revenues related to DSM Programs.

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at certain coal-fired generating plants pursuant to specific regulatory orders.  Such costs are being recovered through utility rates through 2045. 

Unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return.

DSM Programs represent deferred costs associated with such programs.  As a result of an April 2014 SCPSC order, deferred costs are currently being recovered over approximately ten years through an approved rate rider.  See Rate Matters - Electric - Base Rates above for details regarding the 2014 filing with the SCPSC regarding recovery of these deferred costs.

Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 33 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. In 2014, $16.2 million of the reserve was applied to offset incremental storm damage costs. Also, as discussed at Rate Matters - Electric - Base Rates, in April 2014 $5.0 million of the reserve was applied to offset unrecovered net lost margin revenues related to DSM Programs.

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.

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3. EQUITY

Changes in common equity during the nine months ended September 30, 2014 and 2013 were as follows:

Millions of dollars	Common Stock		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total Equity
Balance at January 1, 2014	$	2,479	$	1,896		$	(3	)	$	117		$	4,489
Earnings available to common shareholder			374						9			383
Deferred cost of employee benefit plans						—						—
Total Comprehensive Income			374			—			9			383
Capital contributions from parent	82											82
Cash dividend declared			(192		)				(5		)	(197		)
Balance at September 30, 2014	$	2,561	$	2,078		$	(3	)	$	121		$	4,757
Balance at January 1, 2013	$	2,167	$	1,766		$	(4	)	$	114		$	4,043
Earnings available to common shareholder			311						8			319
Deferred cost of employee benefit plans						1						1
Total Comprehensive Income			311			1			8			320
Capital contributions from parent	285											285
Cash dividend declared			(190		)				(5		)	(195		)
Balance at September 30, 2013	$	2,452	$	1,887		$	(3	)	$	117		$	4,453

SCE&G had 50 million shares of common stock authorized as of September 30, 2014 and December 31, 2013, 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 September 30, 2014 and December 31, 2013, of which 1,000 shares at a stated value of $100,000 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 May 2014, SCE&G issued $300 million of 4.5% first mortgage bonds due June 1, 2064. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

In March 2013, SCE&G entered into a contract for the purchase of nuclear fuel totaling $100 million and payable in 2016.

In January 2013, JEDA issued at a premium, for the benefit of SCE&G, $39.5 million of 4.00% 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.

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Liquidity

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

Millions of dollars	September 30, 2014			December 31, 2013
Lines of credit:
Total committed long-term	$	1,400		$	1,400
Outstanding commercial paper (270 or fewer days)	$	361		$	251
Weighted average interest rate	0.28		%	0.27		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	1,039		$	1,149

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). In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million. In October 2014, the term of the five-year agreements was extended by one year, such that they expire in October 2019. The three-year agreement expires in October 2016. 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. Consolidated SCE&G expects to replace the letters of credit 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 were not significant for any period presented. At September 30, 2014 and December 31, 2013, Consolidated SCE&G had outstanding money pool borrowings from an affiliate of $20.8 million and $27.3 million, respectively.

5. INCOME TAXES

During 2013 SCANA amended certain of its consolidated tax returns to claim certain tax-defined research and development deductions and credits. In connection with these filings, Consolidated SCE&G recorded an unrecognized tax benefit of $3.0 million. During 2014 SCANA filed its 2013 tax return and amended additional tax returns to claim certain tax-defined research and development deductions and credits. In connection with these filings, Consolidated SCE&G increased its unrecognized tax benefit by $8.2 million (for a total of $11.2 million). If recognized, this tax benefit would affect Consolidated SCE&G's effective tax rate. No other material changes in the status of Consolidated SCE&G’s tax positions have occurred through September 30, 2014. These amended returns are now under examination by the IRS.

                Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  Because no refunds related to the unrecognized tax benefits have yet been received, Consolidated SCE&G has not recorded any interest expense or penalties associated with them.

Additionally, during the third quarter of 2013, the IRS issued final regulations regarding the capitalization of certain costs for income tax purposes and re-proposed certain other related regulations (collectively referred to as tangible personal property regulations).  Related IRS revenue procedures were then issued on January 24, 2014. These regulations and procedures did not and are not expected to have a material impact on Consolidated SCE&G's financial position, results of operations or cash flows.

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6. DERIVATIVE FINANCIAL INSTRUMENTS

Consolidated SCE&G recognizes all derivative instruments as either assets or liabilities in the statement of financial position and measures those instruments at fair value.  Consolidated SCE&G recognizes changes in the fair value of derivative instruments either in earnings or within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. 

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. Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are no longer designated as cash flow hedges, and fair value changes and settlement amounts are recorded as regulatory assets and liabilities. Upon settlement, losses on swaps will be amortized over the lives of related debt issuances, and gains may be applied to under-collected fuel, may be amortized to interest expense or may be applied as otherwise directed by the SCPSC.

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 $36.4 million at September 30, 2014 and $36.4 million at December 31, 2013. Consolidated SCE&G was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.1 billion at September 30, 2014 and $1.3 billion at December 31, 2013, respectively.

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 September 30, 2014
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	2
				Other deferred credits and other liabilities	4
Total					$	6
Not designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	102
				Other deferred credits and other liabilities	51
Total					$	153
As of December 31, 2013
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	1
Total					$	1
Not designated as hedging instruments
Interest rate contracts	Prepayments and other	$	13	Derivative financial instruments	$	1
	Other deferred debits and other assets	19
Total		$	32		$	1

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

Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Deferred in Regulatory Accounts						Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)						(Effective Portion)
Millions of dollars	2014			2013		Location	2014			2013
Three Months Ended September 30,
Interest rate contracts	$	(1	)	$	19	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(5	)	$	115	Interest expense	$	(2	)	$	(2	)

Hedge Ineffectiveness

Other gains (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three and nine months ended September 30, 2014 and 2013, respectively.

Derivatives not designated as Hedging Instruments
Millions of dollars	Loss Deferred in Regulatory Accounts			Gain Reclassified from Deferred Accounts into Income
				Location	Amount
Three Months Ended September 30, 2014
Interest rate contracts	$	(35	)	Other income	$	5
Nine Months Ended September 30, 2014
Interest rate contracts	$	(220	)	Other income	$	60

For the three and nine months ended September 30, 2013, no losses were deferred in regulatory accounts, and no amounts were reclassified from deferred accounts into income. As of September 30, 2014, Consolidated SCE&G expects that during the next 12 months reclassifications from other current liabilities and deferred regulatory accounts to earnings arising from derivatives not designated as hedges will include $9.6 million as an increase to other income. The effect of this increase on net income will be entirely offset by net lost margin revenues from DSM Programs as further described in Note 2.

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. 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 permit the secured party to demand the posting of 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 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 may require Consolidated SCE&G to provide collateral upon the occurrence of specific events, primarily credit downgrades.  As of September 30, 2014 and December 31, 2013, Consolidated SCE&G has posted $40.1 million and $1.5 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 condensed consolidated balance sheets. Collateral related to noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the condensed consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of September 30, 2014 and December 31, 2013, Consolidated SCE&G could have been required to post an additional $118.6 million and $- , 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 September 30, 2014 and December 31, 2013 is $158.6 million and $1.0 million, respectively.

In addition, as of September 30, 2014 and December 31, 2013, 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 September 30, 2014 and December 31, 2013, Consolidated SCE&G could request $- and $31.7 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 September 30, 2014 and December 31, 2013 is $- and $31.7 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 September 30, 2014
Interest rate contracts	—	—	—	—	—	—

As of December 31, 2013
Interest rate contracts	$	32	—	$	32	$	(1	)	—	$	31
Balance Sheet Location	Prepayments and other			$	13
	Other deferred debits and other assets			19
	Total			$	32

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 September 30, 2014
Interest rate contracts	$	159	—	$	159	—	$	(40	)	$	119
Balance Sheet Location	Derivative financial instruments			$	104
	Other deferred credits and other liabilities			55
	Total			$	159

As of December 31, 2013
Interest rate contracts	$	2	—	$	2	$	(1	)	$	(1	)	—
Balance Sheet Location	Derivative financial instruments			$	2

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 Level 2 measurements were as follows: 

Millions of dollars		September 30, 2014		December 31, 2013
Assets -	Interest rate contracts	—		$	32
Liabilities -	Interest rate contracts	$	159	2

There were no Level 1 or Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during the periods presented.

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Financial instruments for which the carrying amount may not equal estimated fair value at September 30, 2014 and December 31, 2013 were as follows:

	September 30, 2014				December 31, 2013
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,344.3	$	4,950.6	$	4,054.9	$	4,433.0

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.  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.

8. EMPLOYEE BENEFIT PLANS

Pension and Other Postretirement Benefit Plans

Consolidated SCE&G participates in SCANA’s noncontributory defined benefit pension plan, which covers the majority of 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	2014			2013			2014			2013
Three months ended September 30,
Service cost	$	4.0		$	4.1		$	0.7		$	1.0
Interest cost	8.4			8.0			2.3			2.1
Expected return on assets	(13.9		)	(12.7		)	—			—
Prior service cost amortization	0.9			1.3			—			0.1
Charge due to curtailment	—			8.4			—			—
Amortization of actuarial losses	0.8			3.0			(0.2		)	0.7
Net periodic benefit cost	$	0.2		$	12.1		$	2.8		$	3.9

Nine months ended September 30,
Service cost	$	12.0		$	13.7		$	2.7	$	3.5
Interest cost	25.6			24.0			7.1		6.5
Expected return on assets	(42.2		)	(38.7		)	—		—
Prior service cost amortization	2.6			4.1			0.2		0.4
Charge due to curtailment	—			8.4			—		—
Amortization of actuarial losses	3.0			12.2			—		2.0
Net periodic benefit cost	$	1.0		$	23.7		$	10.0	$	12.4

No significant contribution to the pension trust is expected for the foreseeable future, nor is a limitation on benefit payments expected to apply. SCE&G recovers current pension costs through either a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations. Certain pension costs arising prior to 2013 were deferred for future recovery under regulatory orders as discussed in Note 2.

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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 SCE&G's nuclear power plant. Price-Anderson provides funds up to $13.6 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 $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 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 $84.8 million per incident, but not more than $12.6 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 insurance 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 resulting from an event of nuclear origin. 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 $43.5 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, 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 Consolidated SCE&G’s results of operations, cash flows and financial position.

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 current ownership share in the New Units is 55%. Under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, will acquire an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and will acquire the final 2% no later than the second anniversary of such commercial operation date. Under the terms of the agreement SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost of the percentage conveyed as of the date of conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction will not affect the payment obligations between the parties during construction for the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA.

Under the BLRA, the SCPSC has approved, among other things, the milestone schedule and capital costs estimates schedule for the New Units. The effect of this approval is that it constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. The BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Such annual rate changes are described in Note 2.

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 have impacted the project budget and schedule. SCE&G expects to resolve all

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disputes through both the informal and formal procedures and anticipates that any costs that arise through such dispute resolution processes, as well as other costs identified from time to time, will be recoverable through rates.

In November 2012, the SCPSC approved a petition by SCE&G under the BLRA for an updated milestone schedule and additional updated capital costs for the New Units. In addition, the SCPSC 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 known claims by the Consortium 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. Immediately thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its order, and 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, contending that the SCPSC erred in granting approval of the updated capital costs for the New Units. On October 22, 2014, the South Carolina Supreme Court affirmed the SCPSC's order.

The substantial completion dates currently approved by the SCPSC for Units 2 and 3 are March 15, 2017 and May 15, 2018. The SCPSC has also approved an 18-month contingency period beyond each of these dates. As of September 30, 2014, SCE&G's 55% share of the estimated cash outlays (future value, excluding AFC) totaled approximately $5.5 billion for plant and related transmission infrastructure costs, based on historical one-year and five-year escalation rates as required by the SCPSC. As of September 30, 2014, and based on the updated milestone schedule and capital costs schedule approved by the SCPSC in November 2012 (see above), SCE&G estimated such cost will be approximately $500 million for the additional 5% interest being acquired from Santee Cooper.

Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule for fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules have been and remain focus areas of the Consortium, including sub-modules for module CA20, which is part of the auxiliary building, and CA01, which houses components inside the containment vessel. Modules CA20 and CA01, as well as shield building modules, are considered critical path items for both New Units. CA20 was placed on the nuclear island of Unit 2 in May 2014. The delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow it to be ready for placement on the nuclear island of Unit 2 during the first half of 2015.

During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the schedules and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and design resource allocations, procurement, construction work crew efficiencies, and other items. The result will be a revised fully integrated project schedule with timing of specific construction activities along with detailed information on budget, cost and cash flow requirements. While this detailed re-baselining of construction schedules has not been completed, in August 2014, SCE&G received preliminary information in which the Consortium has indicated that the substantial completion of Unit 2 is expected to occur in late 2018 or the first half of 2019 and that the substantial completion of Unit 3 may be approximately 12 months later. These expected substantial completion dates do not reflect all efforts that may be possible to mitigate delay, nor has SCE&G accepted this new schedule.

Also in August 2014, the IRS notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. To the extent that production tax credits are realized, their benefits are expected to be provided to SCE&G's electric customers.

The Consortium has also provided preliminary cost estimates for Units 2 and 3 principally related to delays for non-firm and non-fixed scopes of work to achieve the late 2018 substantial completion date for Unit 2 and a substantial completion date for Unit 3 approximately 12 months later. SCE&G's 55% portion of this preliminary estimate is approximately $660 million. This figure is presented in 2007 dollars and would be subject to escalation. This figure also excludes any owner's cost amounts associated with the delays, which amounts could be significant. Further, this figure does not reflect consideration of the liquidated damages provisions of the EPC Contract which would partly mitigate any such delay-related costs. The Consortium's preliminary schedule and the cost estimate information have not been accepted by SCE&G and are under review. It is anticipated that further study, evaluation and negotiations will occur. SCE&G plans to reevaluate and reschedule its owners cost estimates and cash flow requirements in light of that new schedule when it is finalized. SCE&G anticipates that the revised schedule and cost estimate will be finalized sometime in 2015.

The milestone schedule approved by the SCPSC in November 2012 provides for 146 milestone dates, which are each subject to an 18-month schedule contingency. As of October 31, 2014, 100 milestones have been completed. The completion

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dates for two of the remaining milestones have been extended beyond their 18-month contingency periods, and it is anticipated that the completion dates for a number of the other remaining milestone dates will also extend beyond their contingency periods. Upon completion of the re-baselining and the finalization of the revised schedule and cost estimate at completion, SCE&G, as provided for under the BLRA, expects to petition the SCPSC for an order to update the BLRA milestone schedule and capital costs estimates schedule. The BLRA provides that the SCPSC shall grant the petition for modification if the record justifies a finding that the change is not the result of imprudence by SCE&G.

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.  SCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the construction and operation of the New Units, and prepared and submitted an integrated response plan for the New Units to the NRC in August 2013. SCE&G cannot predict what additional regulatory or other outcomes may be implemented, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New Units.

Environmental

As part of the President's Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA was directed to issue a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The rule became final on January 8, 2014 and requires 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-fired plants can be constructed without carbon capture and sequestration capabilities. Consolidated SCE&G is evaluating the final rule, but does not plan to construct new coal-fired units in the foreseeable future.

The Memorandum also directed the EPA to issue standards, regulations, or guidelines for existing units. On June 2, 2014, the EPA released the Clean Power Plan, a proposal to regulate carbon dioxide emissions from existing units. The proposed rule includes state-specific goals for carbon dioxide emissions, as well as guidelines for states to follow in developing SIPs to achieve those goals. Consolidated SCE&G is evaluating the proposed rule which may be revised before it becomes final in June 2015. As currently proposed, states will have from one to three years from the date of any final rule to issue SIPs that will ultimately define the specific compliance methodology that will be applied to existing units in that state. Consolidated SCE&G expects that any costs incurred to comply with such requirements will be recoverable through rates.

In 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states 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 Court of Appeals 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. On April 29, 2014, the U. S. Supreme Court reversed the judgment of the Court of Appeals and CSAPR was remanded to the Court of Appeals for further proceedings consistent with the U. S. Supreme Court opinion. On October 23, 2014, the Court of Appeals granted EPA's June 26, 2014 motion to lift the stay of the CSAPR. EPA's motion asked the court to postpone the CSAPR compliance deadlines by three years, so that CSAPR's Phase 1 emission budgets will apply starting in 2015, and CSAPR's Phase 2 emission budgets will apply in 2017 and subsequent years. Air quality control installations that SCE&G and GENCO have already completed have allowed Consolidated SCE&G to comply with the reinstated CAIR and will also allow it to comply with CSAPR.  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.

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The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule was published in the Federal Register on June 7, 2013, and is expected to be finalized September 30, 2015. The EPA expects compliance within a three to six year time frame as NPDES permits are renewed.

On August 15, 2014, the EPA finalized a rule (effective October 14, 2014) that modifies requirements for existing cooling water intake structures. Consolidated SCE&G is conducting studies and is developing or implementing compliance plans for this rule. Congress is also expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones. These provisions, if passed, could have a material impact on the financial condition, results of operations and cash flows of Consolidated SCE&G. Consolidated SCE&G believes that any additional costs imposed by such regulations, including compliance therewith, would be recoverable through rates.

In response to a federal court order to establish a definite timeline for a CCR rule and subsequent obligation via consent decree, the EPA committed to issue new federal regulations affecting the management and disposal of CCRs, such as ash, by December 19, 2014. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO. While Consolidated SCE&G cannot predict how extensive the regulations will be, Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates.

The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998. The Nuclear Waste Act also imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. To date, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017, and is constructing a dry cask storage facility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1. SCE&G may evaluate other technology as it becomes available. See Note 2.

The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. In addition, the state of South Carolina has similar laws. Consolidated SCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify Consolidated SCE&G that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates.

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 through 2017 and will cost an additional $19.5 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 September 30, 2014, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $35.9 million and are included in regulatory assets.

10. AFFILIATED TRANSACTIONS

CGT transports natural gas to SCE&G to serve retail gas customers and certain electric generation requirements.  Such purchases totaled approximately $6.9 million and $8.4 million for the three months ended September 30, 2014 and 2013, respectively, and $21.6 million and $25.3 million for the nine months ended September 30, 2014 and 2013, respectively.  SCE&G's payables to CGT for transportation services were $3.1 million at September 30, 2014 and $3.3 million at December 31, 2013. SCE&G's receivables from CGT for transportation services were $- million at September 30, 2014 and $1.3 million at December 31, 2013.

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 $46.8 million and $43.4 million for the three months

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ended September 30, 2014 and 2013, respectively, and $154.1 million and $132.7 million for the nine months ended September 30, 2014 and 2013, respectively.  SCE&G’s payables to SEMI for such purposes were $14.5 million at September 30, 2014 and $12.5 million at December 31, 2013.

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 accounts for this investment using the equity method.  SCE&G’s total purchases from this affiliate were $82.4 million and $41.9 million for the three months ended September 30, 2014 and 2013, respectively, and $191.9 million and $73.7 million for the nine months ended September 30, 2014 and 2013, respectively.  SCE&G’s total sales to this affiliate were $82.0 million and $41.8 million for the three months ended September 30, 2014 and 2013, respectively, and $190.9 million and $73.4 million for the nine months ended September 30, 2014 and 2013, respectively. SCE&G’s receivable from this affiliate was $26.9 million at September 30, 2014 and $18.0 million at December 31, 2013.  SCE&G’s payable to this affiliate was $27.0 million at September 30, 2014 and $18.0 million at December 31, 2013.

SCANA Services provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems services, telecommunications 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. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services were $65.0 million and $63.5 million for the three months ended September 30, 2014 and 2013, respectively, and $211.4 million and $209.2 million for the nine months ended September 30, 2014 and 2013, respectively. Consolidated SCE&G's payables to SCANA Services for these services were $47.0 million at September 30, 2014 and $49.1 million at December 31, 2013.

Money pool borrowings from an affiliate are described in 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.

	External		Operating			Earnings Available to
Millions of dollars	Revenue		Income			Common Shareholder
Three Months Ended September 30, 2014
Electric Operations	$	740	$	274		n/a
Gas Distribution	72		(2		)	n/a
Adjustments/Eliminations	—		—			$	154
Consolidated Total	$	812	$	272		$	154

Nine Months Ended September 30, 2014
Electric Operations	$	2,032	$	616	n/a
Gas Distribution	337		40		n/a
Adjustments/Eliminations	—		—		$	374
Consolidated Total	$	2,369	$	656	$	374

Three Months Ended September 30, 2013
Electric Operations	$	706	$	257		n/a
Gas Distribution	70		(2		)	n/a
Adjustments/Eliminations	—		—			$	136
Consolidated Total	$	776	$	255		$	136

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Nine Months Ended September 30, 2013
Electric Operations	$	1,903	$	588	n/a
Gas Distribution	297		37		n/a
Adjustments/Eliminations	—		—		$	311
Consolidated Total	$	2,200	$	625	$	311

	September 30,		December 31,
Segment Assets	2014		2013
Electric Operations	$	9,898	$	9,488
Gas Distribution	709		686
Adjustments/Eliminations	2,792		2,526
Consolidated Total	$	13,399	$	12,700

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

SOUTH CAROLINA ELECTRIC & GAS COMPANY

The following discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations appearing in SCE&G’s Annual Report on Form 10-K for the year ended December 31, 2013. 

RESULTS OF OPERATIONS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2014

AS COMPARED TO THE CORRESPONDING PERIODS IN 2013

Net Income

Net income for Consolidated SCE&G was as follows:

	Third Quarter						Year to Date
Millions of dollars	2014		Change		2013		2014		Change		2013
Net income	$	156.9	12.6	%	$	139.3	$	382.5	19.9	%	$	319.1

Third Quarter and Year to Date

Net income increased primarily due to higher electric margins (resulting primarily from the effects of weather and base rate increases under the BLRA), higher gas margins, and other income. These increases were partially offset by higher operation and maintenance expenses, higher property taxes, higher depreciation expense, and higher interest cost, as further described below.

Dividends Declared

Consolidated SCE&G’s Boards of Directors declared the following dividends on common stock (all of which was held by SCANA) during 2014:

Declaration Date	Amount	Quarter Ended	Payment Date
February 20, 2014	$64.3 million	March 31, 2014	April 1, 2014
April 24, 2014	$64.4 million	June 30, 2014	July 1, 2014
July 31, 2014	$68.5 million	September 30, 2014	October 1, 2014
October 30, 2014	$74.4 million	December 31, 2014	January 1, 2015

Electric Operations

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

	Second Quarter						Year to Date
Millions of dollars	2014		Change		2013		2014		Change		2013
Operating revenues	$	740.4	4.9	%	$	706.0	$	2,032.7	6.8	%	$	1,903.2
Less: Fuel used in generation	213.3		7.9	%	197.6		639.9		11.4	%	574.5
Purchased power	13.1		(30.7	)%	18.9		54.4		56.8	%	34.7
Margin	$	514.0	5.0	%	$	489.5	$	1,338.4	3.4	%	$	1,294.0

Third Quarter

Electric margin increased due to the effects of weather of $12.9 million, base rate increases under the BLRA of $15.6 million and customer growth of $4.0 million. These margin increases were partially offset by $4.4 million of downward

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adjustments to electric revenues pursuant to the SCPSC orders related to SCE&G's DSM Programs. These adjustments to electric revenues were fully offset by the recognition, within other income, of gains realized upon the late 2013 settlement of certain derivative interest rate contracts which had been deferred in regulatory accounts.

Year to Date

Electric margin increased due to the effects of weather of $46.4 million, base rate increases under the BLRA of $40.4 million and customer growth of $11.7 million. These margin increases were partially offset by $64.6 million of downward adjustments to electric revenues pursuant to the SCPSC orders related to fuel cost recovery and SCE&G's DSM Programs. These adjustments to electric revenues were fully offset by the recognition, within other income, of gains realized upon the late 2013 settlement of certain derivative interest rate contracts and the application, as a reduction to operation and maintenance expenses, of a portion of SCE&G's storm damage reserve, both of which had been deferred in regulatory accounts.

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

	Third Quarter				Year to Date
Classification	2014	Change		2013	2014	Change		2013
Residential	2,315	4.5	%	2,216	6,370	8.7	%	5,858
Commercial	2,100	1.3	%	2,073	5,676	2.8	%	5,520
Industrial	1,668	5.3	%	1,584	4,662	3.5	%	4,505
Other	170	3.7	%	164	459	3.8	%	442
Total Retail Sales	6,253	3.6	%	6,037	17,167	5.2	%	16,325
Wholesale	258	5.3	%	245	737	0.1	%	736
Total Sales	6,511	3.6	%	6,282	17,904	4.9	%	17,061

Third Quarter and Year to Date

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

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:

	Third Quarter						Year to Date
Millions of dollars	2014		Change		2013		2014		Change		2013
Operating revenues	$	71.8	2.4	%	$	70.1	$	336.7	13.4	%	$	297.0
Less: Gas purchased for resale	45.4		0.7	%	45.1		210.1		18.8	%	176.8
Margin	$	26.4	5.6	%	$	25.0	$	126.6	5.3	%	$	120.2

Third Quarter

Margin increased primarily due to residential and commercial customer growth.

Year to Date

Margin increased primarily due to residential and commercial customer growth of $2.8 million and increased average usage of $2.5 million. SCE&G's WNA mitigates weather-related fluctuations in margin but has no impact on volumes.

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

	Third Quarter				Year to Date
Classification (in thousands)	2014	Change		2013	2014	Change		2013
Residential	686	0.7	%	681	10,266	22.2	%	8,400
Commercial	2,355	2.1	%	2,307	10,138	9.7	%	9,245
Industrial	4,467	(8.0	)%	4,857	13,681	(10.6	)%	15,307
Transportation	1,145	6.1	%	1,079	3,009	(14.7	)%	3,527
Total	8,653	(3.0	)%	8,924	37,094	1.7	%	36,479

Third Quarter

Residential and commercial sales volumes increased primarily due to customer growth. Industrial sales volumes decreased due to a customer switching to an alternative fuel source.

Year to Date

Residential and commercial sales volumes increased primarily due to the effects of weather, customer growth and increased average usage. Industrial sales volumes decreased due to weather-related curtailments and a customer switching to an alternative fuel source. Transportation sales volumes decreased primarily due to weather related curtailments.

Other Operating Expenses

Other operating expenses were as follows:

	Third Quarter						Year to Date
Millions of dollars	2014		Change		2013		2014		Change		2013
Other operation and maintenance	$	135.9	2.9	%	$	132.1	$	415.3	2.3	%	$	405.8
Depreciation and amortization	78.8		0.6	%	78.3		236.4		0.8	%	234.5
Other taxes	53.3		7.2	%	49.7		158.2		6.3	%	148.8

Third Quarter

Other operation and maintenance expenses increased primarily due to higher electric operating expenses of $2.0 million and other general expenses of $2.1 million. These increases were partially offset by lower labor costs of $1.3 million. Depreciation and amortization expense increased due to net plant additions. Other taxes increased primarily due to higher property taxes.

Year to Date

Other operation and maintenance expenses increased primarily due to higher electric operating expenses of $1.8 million, DSM Programs cost amortization of $1.8 million, storm expenses of $1.3 million and other general expenses of $1.6 million. Depreciation and amortization expense increased due to net plant additions.  Other taxes increased primarily due to higher property taxes.

Other Revenue (Expense)

Other revenue (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.  Other revenue increased primarily due to the recognition of $59.6 million of gains realized upon the late 2013 settlement of certain interest rate derivative contracts previously recorded as regulatory liabilities pursuant to SCPSC orders previously discussed. Such gain recognition was fully offset by downward adjustments to revenues reflected within electric margin and had no effect on net income.

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Interest Expense

Interest charges increased primarily due to increased borrowings.

Income Taxes

Income taxes increased primarily due to higher income before taxes.

LIQUIDITY AND CAPITAL RESOURCES

Consolidated SCE&G anticipates that its cash obligations will be met through internally generated funds, the incurrence of additional short- and long-term indebtedness, and equity contributions from its parent company.  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 nine and 12 months ended September 30, 2014 was 4.08 and 3.79, respectively.

SCE&G received approximately $82 million during the nine months ended September 30, 2014 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.  Consolidated SCE&G expects to replace the letters of credit in the fourth quarter of 2014.

At September 30, 2014, Consolidated SCE&G had net available liquidity of approximately $1.1 billion, comprised of cash on hand and available amounts under lines of credit. The credit agreements total an aggregate of $1.4 billion, of which $200 million is scheduled to expire in October 2016 and the terms of the other credit agreements have been extended and are scheduled to expire in October 2019. 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 21 years and bears an average interest cost of 5.6%.  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.

In October 2014, SCE&G's authority from FERC to issue short-term indebtedness and to assume liabilities as a guarantor (pursuant to Section 204 of the Federal Power Act) was renewed. 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. In October 2014, GENCO obtained FERC authority to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2016.

SCE&G's current preliminary estimates of its capital expenditures for new nuclear construction (including transmission) for 2014 through 2016, which are subject to continuing review and adjustment, are $806 million in 2014, $916 million in 2015, and $693 million in 2016.

For additional information, see Note 4 to the consolidated financial statements.

OTHER MATTERS

In June 2014, the Distributed Energy Resource Act became law in South Carolina.  Among other things, this law (i) authorizes SCE&G, at its discretion, to implement a distributed energy resource program and recover the reasonable and prudent costs incurred in implementing such a program, (ii) permits non-utilities and utilities to lease renewable electric generation facilities to homeowners and businesses, and (iii) requires the SCPSC to establish a net energy metering rate methodology.  SCE&G is actively participating, along with numerous other stakeholders, in the SCPSC’s net energy metering proceeding; a hearing in this matter has been set for February 3, 2015.  SCE&G is evaluating its options under the law for implementing a distributed energy program.

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For information related to environmental matters, nuclear generation, and claims and litigation, see Note 9 to the condensed consolidated financial statements.

ITEM 4. CONTROLS AND PROCEDURES

As of September 30, 2014, 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 September 30, 2014, 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 September 30, 2014, that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.

PART II.  OTHER INFORMATION

ITEM 5.    OTHER INFORMATION

SCANA and SCE&G:

SCANA and SCE&G post information from time to time regarding developments relating to SCE&G’s new nuclear project and other matters of interest to investors on SCANA’s website at www.scana.com (which is not intended to be an active hyperlink; the information on SCANA’s website is not a part of this report or any other report or document that SCANA or SCE&G files with or furnishes to the SEC).  On SCANA’s homepage, there is a yellow box containing links to the New Nuclear Development and Other Investor Information sections of the website.  The New Nuclear Development section in turn contains a yellow box with a link to project news and updates. The Other Investor Information section of the website contains a link to recent investor related information that cannot be found at other areas of the website.  Some of the information that will be posted from time to time, including the quarterly reports that SCE&G submits to the SCPSC and the ORS in connection with the new nuclear project, may be deemed to be material information that has not otherwise become public. Investors, media and other interested persons are encouraged to review this information and can sign up, under the Investor Relations Section at www.scana.com (which is not intended to be an active hyperlink; the information on SCANA’s website is not a part of this report or any other report or document that SCANA or SCE&G files with or furnishes to the SEC) for an email alert when there is a new posting in the New Nuclear Development and Other Investor Information yellow box.

SCANA:

The following information is included herein in lieu of filing it in Item 1.01 of Form 8-K:

Indemnification

On November 6, 2014, consistent with its past practice, SCANA entered into an indemnification agreement with Kenneth R. Jackson in connection with his promotion in 2014.

The indemnification agreement generally provides that SCANA will indemnify the covered officer for claims arising in such person's capacity as a director, officer, employee or other agent of SCANA or its subsidiaries, provided that, among other things, such officer acted in good faith and with a view to the best interests of SCANA and, with respect to any criminal proceeding, had no reasonable grounds for believing that his conduct was unlawful. The indemnification agreement also provides for payment for or reimbursement of reasonable expenses incurred by an indemnitee who is a party to a proceeding in advance of final disposition of the proceeding under certain circumstances.

The above description of the indemnification agreement is qualified in its entirety by reference to the form of indemnification agreement that was filed as Exhibit 10.01 to SCANA's Quarterly Report on Form 10-Q for the period ended June 30, 2012 and that is incorporated herein by reference.

ITEM 6. EXHIBITS

SCANA and SCE&G:

65

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

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.  The signature of each registrant shall be deemed to relate only to matters having reference to such registrant and any subsidiaries thereof.

SCANA CORPORATION

SOUTH CAROLINA ELECTRIC & GAS COMPANY

(Registrants)

	By:	/s/James E. Swan, IV
Date: November 10, 2014		James E. Swan, IV
		Controller
		(Principal accounting officer)

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EXHIBIT INDEX

	Applicable to Form 10-Q of
Exhibit No.	SCANA	SCE&G	Description
3.01	X		Restated Articles of Incorporation of SCANA, as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference herein)
3.02	X		Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. 33-62421 and incorporated by reference herein)
3.03	X		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)
10.01	X		Form of Indemnification Agreement (Filed as Exhibit 10.01 to Form 10-Q for the period ended June 30, 2012 and incorporated by reference herein)
12.01	X	X	Statement Re Computation of Ratios (Filed herewith)
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.

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EX-12.01

Exhibit 12.01

COMPUTATION OF RATIOS

September 30, 2014

RATIO OF EARNINGS TO FIXED CHARGES

SCANA:	Nine Months Ended September 30, 2014			Twelve Months Ended September 30, 2014			Years ended December 31,
Dollars in Millions							2013			2012			2011			2010			2009
Fixed Charges as defined:
Interest on debt		$237.6			$314.8			$305.9			$301.3			$287.0			$270.4			$251.5
Amortization of debt premium, discount and expense (net)	5.9			7.2			5.3			4.9			4.8			5.1			4.8
Interest component on rentals	3.0			4.3			4.9			4.9			5.2			4.6			7.9
Preference security dividend requirement of consolidated subsidiary	-			-			-			-			-			-			14.2
Total Fixed Charges (A)		$246.5			$326.3			$316.1			$311.1			$297.0			$280.1			$278.4
Earnings as defined:
Pretax income from continuing operations		$631.2			$787.6			$693.8			$601.6			$555.6			$535.4			$524.2
Total fixed charges above	246.5			326.3			316.1			311.1			297.0			280.1			278.4
Pretax equity in (earnings) losses of investees	(0.7		)	(1.2		)	(3.2		)	(3.3		)	(2.9		)	(1.1		)	(2.2		)
Cash distributions from equity investees	4.5			10.8			9.6			3.3			3.6			4.8			3.3
Preference security dividend requirement from above	-			-			-			-			-			-			(14.2		)
Total Earnings (B)	$881.5			$1,123.5			$1,016.3				$912.7			$853.3			$819.2			$789.5
Ratio of Earnings to Fixed Charges (B/A)	3.58			3.44			3.22			2.93			2.87			2.92			2.84

SCE&G:	Nine Months Ended September 30, 2014		Twelve Months Ended September 30, 2014		Years ended December 31,
Dollars in Millions					2013		2012		2011		2010		2009
Fixed Charges as defined:
Interest on debt		$176.9		$234.4		$226.4		$217.4		$207.8		$192.4		$181.4
Amortization of debt premium, discount and expense (net)	3.4		4.5		4.2		3.9		3.9		4.0		3.8
Interest component on rentals	3.0		4.1		4.5		3.2		3.6		3.1		5.5
Total Fixed Charges (A)		$183.3		$243.0		$235.1		$224.5		$215.3		$199.5		$190.7
Earnings as defined:
Pretax income from continuing operations		$561.1		$671.5		$579.7		$509.5		$456.5		$433.6		$427.8
Total fixed charges above	183.3		243.0		235.1		224.5		215.3		199.5		190.7
Pretax equity in (earnings) losses of investees	4.2		5.6		3.5		3.8		2.3		2.1		0.5
Total Earnings (B)		$748.6		$920.1		$818.3		$737.8		$674.1		$635.2		$619.0
Ratio of Earnings to Fixed Charges (B/A)	4.08		3.79		3.48		3.29		3.13		3.18		3.25

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: November 10, 2014
	/s/Kevin B. Marsh
	Kevin B. Marsh
	Chairman of the Board, President, Chief Executive Officer and
	Chief Operating Officer

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: November 10, 2014
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Executive Vice President and Chief Financial Officer

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: November 10, 2014
	/s/Kevin B. Marsh
	Kevin B. Marsh
	Chairman of the Board and Chief Executive Officer

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: November 10, 2014
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Executive Vice President and Chief Financial Officer

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 September 30, 2014 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: November 10, 2014

/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. 

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 September 30, 2014 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: November 10, 2014

/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. 

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 September 30, 2014 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: November 10, 2014

/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. 

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 September 30, 2014 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: November 10, 2014

/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. 

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details 2) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Derivative [Line Items]
Asset Derivatives Fair Value	$ 10,000,000	$ 21,000,000
Derivative Asset	8,000,000	44,000,000
Derivative Asset, Fair Value, Gross Liability	(2,000,000)	0
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	(1,000,000)
Derivative Liability	187,000,000	28,000,000
Liability Derivatives Fair Value	189,000,000	28,000,000
Derivative Liability Fair Value Gross Amount Offset in the Statement of Financial Position	(2,000,000)	0
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	(1,000,000)
Derivative Liability, Fair Value of Collateral	(69,000,000)	(25,000,000)
Net Fair Value Derivative Asset offset against Collateral	8,000,000	43,000,000
Net Fair Value Derivative Liability offset against Collateral	118,000,000	2,000,000
Interest Rate Derivative Instruments Not Designated as Hedging Instruments, Liability at Fair Value	1,100,000,000	1,300,000,000
Prepayments and other current assets [member]
Derivative [Line Items]
Derivative Asset	6,000,000	21,000,000
Other current liabilities
Derivative [Line Items]
Derivative Liability	112,000,000	10,000,000
Other deferred credits and other liabilities
Derivative [Line Items]
Derivative Liability	75,000,000	18,000,000
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	2,000,000	23,000,000
Derivatives designated as hedging instruments
Derivative [Line Items]
Asset Derivatives Fair Value	1,000,000	2,000,000
Liability Derivatives Fair Value	29,000,000	19,000,000
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Asset Derivatives Fair Value	9,000,000	42,000,000
Liability Derivatives Fair Value	160,000,000	9,000,000
Energy Management Contracts [Member]
Derivative [Line Items]
Asset Derivatives Fair Value	7,000,000	8,000,000
Derivative Asset	6,000,000	8,000,000
Derivative Asset, Fair Value, Gross Liability	(1,000,000)	0
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	0
Derivative Liability	6,000,000	8,000,000
Liability Derivatives Fair Value	7,000,000	8,000,000
Derivative Liability Fair Value Gross Amount Offset in the Statement of Financial Position	(1,000,000)	0
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	0
Derivative Liability, Fair Value of Collateral	(5,000,000)	(6,000,000)
Net Fair Value Derivative Asset offset against Collateral	6,000,000	8,000,000
Net Fair Value Derivative Liability offset against Collateral	1,000,000	2,000,000
Interest Rate Contract
Derivative [Line Items]
Asset Derivatives Fair Value	0	32,000,000
Derivative Asset	0	32,000,000
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	(1,000,000)
Derivative Liability	179,000,000	20,000,000
Liability Derivatives Fair Value	179,000,000	20,000,000
Derivative Liability Fair Value Gross Amount Offset in the Statement of Financial Position	0	0
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	(1,000,000)
Derivative Liability, Fair Value of Collateral	(63,000,000)	(19,000,000)
Net Fair Value Derivative Asset offset against Collateral	0	31,000,000
Net Fair Value Derivative Liability offset against Collateral	116,000,000	0
Interest Rate Contract | Derivatives designated as hedging instruments | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value
Interest Rate Contract | Derivatives designated as hedging instruments | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	4,000,000	5,000,000
Interest Rate Contract | Derivatives designated as hedging instruments | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	22,000,000	14,000,000
Interest Rate Contract | Derivatives designated as hedging instruments | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Asset Derivatives Fair Value
Interest Rate Contract | Not Designated as Hedging Instrument [Member] | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value		13,000,000
Interest Rate Contract | Not Designated as Hedging Instrument [Member] | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	102,000,000	1,000,000
Interest Rate Contract | Not Designated as Hedging Instrument [Member] | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	51,000,000
Interest Rate Contract | Not Designated as Hedging Instrument [Member] | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Asset Derivatives Fair Value		19,000,000
Commodity Contract
Derivative [Line Items]
Asset Derivatives Fair Value	3,000,000	4,000,000
Derivative Asset	2,000,000	4,000,000
Derivative Asset, Fair Value, Gross Liability	(1,000,000)	0
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	0
Derivative Liability	2,000,000
Liability Derivatives Fair Value	3,000,000
Derivative Liability Fair Value Gross Amount Offset in the Statement of Financial Position	(1,000,000)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0
Derivative Liability, Fair Value of Collateral	(1,000,000)
Net Fair Value Derivative Asset offset against Collateral	2,000,000	4,000,000
Net Fair Value Derivative Liability offset against Collateral	1,000,000
Commodity Contract | Derivatives designated as hedging instruments | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value	1,000,000	2,000,000
Commodity Contract | Derivatives designated as hedging instruments | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	3,000,000
Commodity Contract | Not Designated as Hedging Instrument [Member] | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value	2,000,000	2,000,000
Other Energy Management Contract [Member] | Not Designated as Hedging Instrument [Member] | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value	5,000,000	4,000,000
Other Energy Management Contract [Member] | Not Designated as Hedging Instrument [Member] | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	4,000,000	4,000,000
Other Energy Management Contract [Member] | Not Designated as Hedging Instrument [Member] | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	3,000,000	4,000,000
Other Energy Management Contract [Member] | Not Designated as Hedging Instrument [Member] | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Asset Derivatives Fair Value	2,000,000	4,000,000
SCEG
Derivative [Line Items]
Derivative Asset		32,000,000
Derivative Liability	159,000,000
Interest Rate Derivative Instruments Not Designated as Hedging Instruments, Liability at Fair Value	1,100,000,000	1,300,000,000
SCEG | Prepayments and other current assets [member]
Derivative [Line Items]
Derivative Asset		13,000,000
SCEG | Other current liabilities
Derivative [Line Items]
Derivative Liability	104,000,000	2,000,000
SCEG | Other deferred credits and other liabilities
Derivative [Line Items]
Derivative Liability	55,000,000
SCEG | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset		19,000,000
SCEG | Derivatives designated as hedging instruments
Derivative [Line Items]
Asset Derivatives Fair Value
Liability Derivatives Fair Value	6,000,000	1,000,000
SCEG | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Asset Derivatives Fair Value		32,000,000
Liability Derivatives Fair Value	153,000,000	1,000,000
SCEG | Interest Rate Contract
Derivative [Line Items]
Asset Derivatives Fair Value	0	32,000,000
Derivative Asset	0	32,000,000
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	(1,000,000)
Derivative Liability	159,000,000	2,000,000
Liability Derivatives Fair Value	159,000,000	2,000,000
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	(1,000,000)
Derivative Liability, Fair Value of Collateral	(40,000,000)	(1,000,000)
Net Fair Value Derivative Asset offset against Collateral	0	31,000,000
Net Fair Value Derivative Liability offset against Collateral	119,000,000	0
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	2,000,000	1,000,000
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	4,000,000
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Asset Derivatives Fair Value
SCEG | Interest Rate Contract | Not Designated as Hedging Instrument [Member] | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value		13,000,000
SCEG | Interest Rate Contract | Not Designated as Hedging Instrument [Member] | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	102,000,000	1,000,000
SCEG | Interest Rate Contract | Not Designated as Hedging Instrument [Member] | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	51,000,000
SCEG | Interest Rate Contract | Not Designated as Hedging Instrument [Member] | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Asset Derivatives Fair Value		$ 19,000,000

XML

AFFILIATED TRANSACTIONS - SCEG AFFILIATED TRANSACTIONS -SCEG (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Related Party Transaction Purchases from Related Party			$ 191.9	$ 73.7
Related Party Transaction, Amounts of Transaction	82.0	41.8	190.9	73.4
Due to Affiliate, Current	27.0		27.0		18.0
Due from Affiliate, Current	26.9		26.9		18.0
Equity Method Investment, Ownership Percentage	40.00%		40.00%
CGT [Member]
Related Party Transaction [Line Items]
Related Party Transaction Purchases from Related Party	6.9	8.4	21.6	25.3
Due to Affiliate, Current	3.1		3.1		3.3
Due from Affiliate, Current	0		0		1.3
Energy Marketing [Member]
Related Party Transaction [Line Items]
Due to Affiliate, Current	14.5		14.5		12.5
Cost of Natural Gas Purchases	46.8	43.4	154.1	132.7
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Related Party Transaction Purchases from Related Party	82.4	41.9
SCANA Services [Member]
Related Party Transaction [Line Items]
Related Party Transaction Purchases from Related Party			47.0		49.1
Related Party Transaction, Expenses from Transactions with Related Party	$ 65.0	$ 63.5	$ 211.4	$ 209.2

XML

RATE AND OTHER REGULATORY MATTERS (Details 3) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012
Regulatory Liabilities [Line Items]
Regulatory Assets, Noncurrent	$ 1,564.0	$ 1,360.0
Regulatory Liabilities	857	966
SCEG
Regulatory Liabilities [Line Items]
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates	0.60%		2.10%
Regulatory Assets, Noncurrent	1,506.0	1,303.0
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates	2.80%	2.90%	2.30%
Public Utilities, Authorized Allowable Return on Common Equity, Percentage	11.00%
Demand Side Management Program Costs, Noncurrent				15.4	16.9	19.6
Regulatory Liabilities	615	732	732
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates	2.5
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs	100
PSNC Energy [Member]
Regulatory Liabilities [Line Items]
Regulatory Assets, Noncurrent	1.1
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	719	695
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	509	495
Storm damage reserve [Member]
Regulatory Liabilities [Line Items]
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM	5.0
Regulatory Liabilities	6	27
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates	2.5
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs	100
Storm damage reserve [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	6
Monetization bankruptcy claim [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	27	29
Deferred gains on interest rate derivatives [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	83	181
Deferred gains on interest rate derivatives [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	83
Deferred Income Tax Charges [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	22	24
Deferred Income Tax Charges [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	17	19
Planned major maintenance [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	10
Planned major maintenance [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 0

XML

LONG-TERM AND SHORT-TERM DEBT (Tables)

9 Months Ended

Sep. 30, 2014

Short-term Debt [Line Items]

Schedule of Line of Credit Facilities [Table 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	September 30, 2014			December 31, 2013			September 30, 2014			December 31, 2013			September 30, 2014		December 31, 2013
Lines of credit:
Total committed long-term	$	300		$	300		$	1,400		$	1,400		$	100	$	100
Outstanding commercial paper (270 or fewer days)	$	127		$	125		$	361		$	251		—		—
Weighted average interest rate	0.35		%	0.39		%	0.28		%	0.27		%	—		—
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—		—
Available	$	170		$	172		$	1,039		$	1,149		$	100	$	100

SCEG

Short-term Debt [Line Items]

Schedule of Line of Credit Facilities [Table 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	September 30, 2014			December 31, 2013
Lines of credit:
Total committed long-term	$	1,400		$	1,400
Outstanding commercial paper (270 or fewer days)	$	361		$	251
Weighted average interest rate	0.28		%	0.27		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	1,039		$	1,149

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Reported Value Measurement [Member]
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	$ 5,733.2	$ 5,449.3
Reported Value Measurement [Member] | SCEG
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	4,344.3	4,054.9
Estimate of Fair Value Measurement [Member]
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	6,469.6	5,916.3
Estimate of Fair Value Measurement [Member] | SCEG
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	$ 4,950.6	$ 4,433.0

XML

INCOME TAXES (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended	12 Months Ended		9 Months Ended
	Jun. 30, 2014	Dec. 31, 2015	Dec. 31, 2013	Sep. 30, 2014 SCEG	Dec. 31, 2013 SCEG
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits				$ 11.2	$ 3.0
Unrecognized Tax Benefits, Period Increase (Decrease)				$ 8.2
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	6.00%	5.00%	6.90%

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Interest Paid, Capitalized	$ 13	$ 10
SCEG
Interest Paid, Capitalized	$ 11	$ 9

XML

EMPLOYEE BENEFIT PLANS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended			9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 31, 2014	Sep. 30, 2014 Pension Benefits	Sep. 30, 2013 Pension Benefits	Sep. 30, 2014 Pension Benefits	Sep. 30, 2013 Pension Benefits	Sep. 30, 2014 Other Postretirement Benefits	Sep. 30, 2013 Other Postretirement Benefits	Sep. 30, 2014 Other Postretirement Benefits	Sep. 30, 2013 Other Postretirement Benefits	Mar. 31, 2014 SCEG	Sep. 30, 2014 SCEG Pension Benefits	Sep. 30, 2013 SCEG Pension Benefits	Sep. 30, 2014 SCEG Pension Benefits	Sep. 30, 2013 SCEG Pension Benefits	Sep. 30, 2014 SCEG Other Postretirement Benefits	Sep. 30, 2013 SCEG Other Postretirement Benefits	Sep. 30, 2014 SCEG Other Postretirement Benefits	Sep. 30, 2013 SCEG Other Postretirement Benefits	Dec. 31, 2012 Pension Costs [Member] SCEG	Sep. 30, 2014 Pension Costs [Member] SCEG	Dec. 31, 2013 Pension Costs [Member] SCEG
Pension and Other Postretirement Benefit Plans
Pension Contributions	No									No
Components of Net Periodic Benefit Cost
Service cost		$ 5.0	$ 5.1	$ 15.0	$ 16.9	$ 0.9	$ 1.2	$ 3.4	$ 4.4		$ 4.0	$ 4.1	$ 12.0	$ 13.7	$ 0.7	$ 1.0	$ 2.7	$ 3.5
Interest cost		9.9	9.5	30.3	28.4	2.8	2.8	9.0	8.3		8.4	8.0	25.6	24.0	2.3	2.1	7.1	6.5
Expected return on assets		(16.4)	(15.1)	50.0	45.8	0	0	0	0		13.9	12.7	42.2	38.7	0	0	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		1.1	1.5	3.1	4.9	0.1	0.1	0.3	0.5		0.9	1.3	2.6	4.1	0	0.1	0.2	0.4
Defined Benefit Plan, Curtailments			9.9		9.9							8.4		8.4
Defined Benefit Plan, Amortization of Transition Obligations (Assets)				0	0			0	0.3
Defined Benefit Plan, Actuarial Net (Gains) Losses		0.9	3.5	(3.5)	(14.4)	(0.2)	0.8	0	(2.5)		(0.8)	(3.0)	(3.0)	(12.2)	0.2	(0.7)	0	(2.0)
Defined Benefit Plan, Net Periodic Benefit Cost		0.5	14.4	1.9	28.7	3.6	4.9	12.7	16.0		0.2	12.1	1.0	23.7	2.8	3.9	10.0	12.4
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority																			$ 63	$ 14
Regulatory Noncurrent Asset, Amortization Period																			30	12	14

XML

SEGMENT OF BUSINESS INFORMATION (Tables)

9 Months Ended

Sep. 30, 2014

Segment Reporting Information [Line Items]

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

Millions of dollars	External Revenue			Intersegment Revenue			Operating Income			Net Income
Three Months Ended September 30, 2014
Electric Operations	$	739		$	1		$	275		n/a
Gas Distribution	127			—			(6		)	n/a
Retail Gas Marketing	68			—			n/a			$	(3	)
Energy Marketing	182			47			n/a			(2		)
All Other	9			103			7			(5		)
Adjustments/Eliminations	(4		)	(151		)	(7		)	154
Consolidated Total	$	1,121		$	—		$	269		$	144

Nine Months Ended September 30, 2014
Electric Operations	$	2,027		$	5		$	616	n/a
Gas Distribution	728			—			98		n/a
Retail Gas Marketing	367			—			n/a		$	16
Energy Marketing	602			154			n/a		5
All Other	27			317			21		(3		)
Adjustments/Eliminations	(15		)	(476		)	37		415
Consolidated Total	$	3,736		$	—		$	772	$	433

Three Months Ended September 30, 2013
Electric Operations	$	704		$	2		$	257		n/a
Gas Distribution	123			—			(6		)	n/a
Retail Gas Marketing	67			—			n/a			$	(2	)
Energy Marketing	152			44			n/a			1
All Other	11			95			8			(3		)
Adjustments/Eliminations	(6		)	(141		)	(4		)	135
Consolidated Total	$	1,051		$	—		$	255		$	131

Nine Months Ended September 30, 2013
Electric Operations	$	1,898		$	6		$	588	n/a
Gas Distribution	657			—			94		n/a
Retail Gas Marketing	325			—			n/a		$	16
Energy Marketing	488			133			n/a		5
All Other	30			303			22		(2		)
Adjustments/Eliminations	(20		)	(442		)	34		349
Consolidated Total	$	3,378		$	—		$	738	$	368

	September 30,		December 31,
Segment Assets	2014		2013
Electric Operations	$	9,898	$	9,488
Gas Distribution	2,365		2,340
Retail Gas Marketing	121		172
Energy Marketing	110		133
All Other	1,333		1,378
Adjustments/Eliminations	2,044		1,653
Consolidated Total	$	15,871	$	15,164

SCEG

Segment Reporting Information [Line Items]

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

.

	External		Operating			Earnings Available to
Millions of dollars	Revenue		Income			Common Shareholder
Three Months Ended September 30, 2014
Electric Operations	$	740	$	274		n/a
Gas Distribution	72		(2		)	n/a
Adjustments/Eliminations	—		—			$	154
Consolidated Total	$	812	$	272		$	154

Nine Months Ended September 30, 2014
Electric Operations	$	2,032	$	616	n/a
Gas Distribution	337		40		n/a
Adjustments/Eliminations	—		—		$	374
Consolidated Total	$	2,369	$	656	$	374

Three Months Ended September 30, 2013
Electric Operations	$	706	$	257		n/a
Gas Distribution	70		(2		)	n/a
Adjustments/Eliminations	—		—			$	136
Consolidated Total	$	776	$	255		$	136

Nine Months Ended September 30, 2013
Electric Operations	$	1,903	$	588	n/a
Gas Distribution	297		37		n/a
Adjustments/Eliminations	—		—		$	311
Consolidated Total	$	2,200	$	625	$	311

	September 30,		December 31,
Segment Assets	2014		2013
Electric Operations	$	9,898	$	9,488
Gas Distribution	709		686
Adjustments/Eliminations	2,792		2,526
Consolidated Total	$	13,399	$	12,700

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EMPLOYEE BENEFIT PLANS (Tables)

9 Months Ended

Sep. 30, 2014

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2014			2013			2014		2013
Nine months ended September 30,
Service cost	$	15.0		$	16.9		$	3.4	$	4.4
Interest cost	30.3			28.4			9.0		8.3
Expected return on assets	(50.0		)	(45.8		)	—		—
Prior service cost amortization	3.1			4.9			0.3		0.5
Charge due to curtailment	—			9.9			—		—
Transition obligation amortization	—			—			—		0.3
Amortization of actuarial losses	3.5			14.4			—		2.5
Net periodic benefit cost	$	1.9		$	28.7		$	12.7	$	16.0

: 

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2014			2013			2014			2013
Three months ended September 30,
Service cost	$	5.0		$	5.1		$	0.9		$	1.2
Interest cost	9.9			9.5			2.8			2.8
Expected return on assets	(16.4		)	(15.1		)	—			—
Prior service cost amortization	1.1			1.5			0.1			0.1
Charge due to curtailment	—			9.9			—			—
Amortization of actuarial losses	0.9			3.5			(0.2		)	0.8
Net periodic benefit cost	$	0.5		$	14.4		$	3.6		$	4.9

SCEG

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

:

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2014			2013			2014			2013
Three months ended September 30,
Service cost	$	4.0		$	4.1		$	0.7		$	1.0
Interest cost	8.4			8.0			2.3			2.1
Expected return on assets	(13.9		)	(12.7		)	—			—
Prior service cost amortization	0.9			1.3			—			0.1
Charge due to curtailment	—			8.4			—			—
Amortization of actuarial losses	0.8			3.0			(0.2		)	0.7
Net periodic benefit cost	$	0.2		$	12.1		$	2.8		$	3.9

Nine months ended September 30,
Service cost	$	12.0		$	13.7		$	2.7	$	3.5
Interest cost	25.6			24.0			7.1		6.5
Expected return on assets	(42.2		)	(38.7		)	—		—
Prior service cost amortization	2.6			4.1			0.2		0.4
Charge due to curtailment	—			8.4			—		—
Amortization of actuarial losses	3.0			12.2			—		2.0
Net periodic benefit cost	$	1.0		$	23.7		$	10.0	$	12.4

XML

COMMITMENTS AND CONTINGENCIES (Details) (USD $)	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2005	Mar. 31, 2020	Mar. 31, 2019
Environmental
Parties who filed petitions to SCPSC order	two
Phases CAIR set omission limits to be met in	two
Number of years to meet EPA mercury and air pollutants standard	four
NPDES permit renewal permit period	five
SCEG
Nuclear Insurance
Federal Limit on Public Liability Claims from Nuclear Incident Approximate	$ 13,600,000,000
Maximum Insurance Coverage for each Nuclear Plant by ANI	375,000,000
Maximum liability assessment per reactor for each nuclear incident	127,300,000
Maximum Federal Limit on Public Liability Claims Per Incident for Each Year	12,600,000
Maximum yearly assessment per reactor	18,900,000
Maximum Federal Limit on Public Liability Claims per Reactor for each Nuclear Incident at 2/3	84,800,000
Inflation adjustment period for nuclear insurance	5
Maximum retrospective insurance premium per nuclear incident	43,500,000
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
Maximum loss for a single nuclear incident	2,750,000,000
Environmental
Number of MGP decommissioned sites that contain residues of byproduct chemicals	4
Site Contingency MGP Estimated Environmental Remediation Costs	19,500,000
Deferred costs net of costs previously recovered through rates and insurance settlements included in regulatory assets	$ 35,900,000
Current ownership share in New Unit	55.00%
Total additional ownership in new units	5.00%
Additional ownership in new units	1.00%		2.00%	2.00%
Number of states required to reduce emissions to attain mandated levels		28
Total Construction Milestones	146
Milestone Schedule Contingency Period	18
Completed Construction Milestones	100
MIlestones Extended	2
PSNC Energy
Environmental
Number of MGP sites requiring cleanup	5

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended								9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2014 SCEG	Dec. 31, 2013 SCEG	Mar. 31, 2013 SCEG	Dec. 31, 2012 SCEG MW	Sep. 30, 2014 Genco MW	Sep. 30, 2014 PSNC Energy [Member]	Dec. 31, 2013 PSNC Energy [Member]
Significant Accounting Policies
Number of coal fired units to be retired								6	6
Number of Units retired							3
Power generation capacity six coal fired units									730
Power Generation Capacity Megawatts										605
Asset Management and Supply Service Agreements
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)											47.00%	48.00%
Natural gas inventory, carrying amount											$ 25.4	$ 22.8
Property, Plant and Equipment, Net	$ 314		$ 314		$ 317	$ 70	$ 69			$ 502
PercentOfStorageFeesCreditedToRatePayers											75.00%
Earnings Per Share
Weighted Average Shares Outstanding - Basic	142.1	140.1	141.6	138.0
Incremental Shares Attributable Equity Forward Agreements	0	0	0	0.6
Weighted Average Number of Shares Outstanding, Diluted	142.1	140.1	141.6	138.6

XML

RATE AND OTHER REGULATORY MATTERS (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended			3 Months Ended	9 Months Ended		12 Months Ended						12 Months Ended				3 Months Ended	9 Months Ended	12 Months Ended	9 Months Ended		9 Months Ended									9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2014 SCEG	Sep. 30, 2014 SCEG	Sep. 30, 2013 SCEG	May 01, 2015 SCEG	Dec. 31, 2013 SCEG	Dec. 31, 2012 SCEG	Mar. 31, 2014 SCEG	Mar. 31, 2013 SCEG	Mar. 31, 2012 SCEG	Dec. 31, 2013 PSNC Energy	Sep. 30, 2014 PSNC Energy	Sep. 30, 2014 Pension Costs [Member]	Dec. 31, 2013 Pension Costs [Member]	Dec. 31, 2012 Pension Costs [Member] SCEG	Sep. 30, 2014 Pension Costs [Member] SCEG	Dec. 31, 2013 Pension Costs [Member] SCEG	Sep. 30, 2014 Other Regulatory Assets [Member]	Dec. 31, 2013 Other Regulatory Assets [Member]	Sep. 30, 2014 Other Regulatory Assets [Member] SCEG	Dec. 31, 2013 Other Regulatory Assets [Member] SCEG	Sep. 30, 2014 Deferred Pollution Control Costs	Dec. 31, 2013 Deferred Pollution Control Costs	Dec. 31, 2013 Deferred Pollution Control Costs SCEG	Sep. 30, 2014 Franchise agreement Costs	Dec. 31, 2013 Franchise agreement Costs	Sep. 30, 2014 Franchise agreement Costs SCEG	Dec. 31, 2013 Franchise agreement Costs SCEG	Sep. 30, 2014 Planned major maintenance [Member] SCEG	Sep. 30, 2014 Storm damage reserve [Member]
Rate Matters [Line Items]
Amounts Recovered Through Electric Rates to offset Nuclear Related Outage Costs					$ 17.2
Net Lost Revenues associated with DSM programs					6.6
Fuel Costs					10.3
Undercollected balance fuel								46
Carrying costs on deferred income tax assets				1.6	4.1
Storm reserve applied to offset storm damage costs																																16.2
Carrying cost recovery	(7)	0			(7)	0
Regulatory Assets, Noncurrent	1,564.0		1,360.0	1,506.0	1,506.0			1,303.0						1.1	222.0	238.0		201.0	215.0	52.0	48.0	42.0	39.0	36.0	37.0	37.0	27.0	31.0	27.0	31.0
Number of coal fired units to be retired									6		6
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates					2.80%			2.90%	2.30%
Allowable return on common equity (as a percent)					11.00%
Demand Side Management Program Costs, Noncurrent										15.4	16.9	19.6
Regulatory Asset Recovery Assessments							12
Increase (decrease) in retail electric rate requested under the BLRA					66.2			67.2	52.1
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates					0.60%				2.10%
Public Utilities changes in Retail Natural Gas Rates Approved under RSA					2.6				7.5
Public Utilities, Rate Calculation Basis					12-month rolling average								12
Regulatory Noncurrent Asset Amortization Period																	30	12	14	33		50
Amounts Recovered through Electric Rates to offset Turbine Expense																															18.4
Public Utilities Base Fuel under Collected Balance Recovery Period	12				12
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority																	63	14
Derivative, Gain on Derivative					17.8
Storm Damage Reserve Cost Applied					5.0
Reduction to Net Lost Revenues from DSM programs					25.00%
Reduction to DSM Program costs deferred					6.6
Number of Units retired								3
Demand side management recovery period					10
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM																																5.0
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs					$ 100																											$ 100

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Cash Flows From Operating Activities:
Net Income (Loss) Available to Common Stockholders, Basic	$ 433	$ 368
Adjustments to reconcile net income to net cash provided from operating activities:
Income (Loss) from Equity Method Investments, Net of Dividends or Distributions	2	0
Deferred Income Tax Expense (Benefit)	63	62
Depreciation and amortization	298	294
Amortization of nuclear fuel	31	42
Allowance for equity funds used during construction	(26)	(19)
Carrying cost recovery	(7)	0
Cash provided (used) by changes in certain assets and liabilities:
Receivables	111	70
Inventories	(34)	(8)
Prepayments and other	(90)	8
Increase (Decrease) in Pension and Postretirement Obligations	(13)	(133)
Regulatory assets	(171)	142
Regulatory liabilities	(133)	78
Accounts payable	(18)	(32)
Taxes accrued	(69)	(27)
Interest accrued	(3)	(7)
Changes in other assets	16	(46)
Changes in other liabilities	168	(13)
Net Cash Provided From Operating Activities	558	779
Cash Flows From Investing Activities:
Property additions and construction expenditures	(778)	(868)
Proceeds from investments (including derivative collateral posted)	204	199
Purchase of investments (including derivative collateral posted)	(247)	(161)
Payments for (Proceeds from) Hedge, Investing Activities	0	43
Payments for Interest Rate Contract Hedge Investing Activities	(34)	(49)
Net Cash Used in Investing Activities	(855)	(836)
Cash Flows From Financing Activities:
Proceeds from Issuance of Common Stock	75	272
Proceeds from issuance of long-term debt	294	451
Repayments of Long-term Debt	(17)	(256)
Dividends	(220)	(207)
Short-term borrowings, net	111	(245)
Net Cash Provided From Financing Activities	243	15
Net (Decrease) Increase in Cash and Cash Equivalents	(54)	(42)
Cash and Cash Equivalents, January 1	136	72
Cash and Cash Equivalents, September 30	82	30
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	225	222
Cash paid for-Income taxes	246	70
Noncash Investing and Financing Activities:
Accrued construction expenditures	108	97
Capital Lease Obligations Incurred	4	5
Noncash or Part Noncash Acquisition, Value of Assets Acquired	0	98
SCEG
Cash Flows From Operating Activities:
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	383	319
Adjustments to reconcile net income to net cash provided from operating activities:
Income (Loss) from Equity Method Investments	4	0
Deferred Income Tax Expense (Benefit)	76	49
Depreciation and amortization	236	237
Amortization of nuclear fuel	31	42
Allowance for equity funds used during construction	(22)	(18)
Carrying cost recovery	(7)	0
Cash provided (used) by changes in certain assets and liabilities:
Receivables	(34)	(58)
Inventories	(36)	5
Prepayments and other	0	(51)
Increase (Decrease) in Pension and Postretirement Obligations	(12)	(117)
Regulatory assets	(170)	129
Regulatory liabilities	(130)	80
Accounts payable	11	(7)
Taxes accrued	(70)	7
Interest accrued	(6)	(10)
Changes in other assets	3	(30)
Changes in other liabilities	167	(3)
Net Cash Provided From Operating Activities	424	574
Cash Flows From Investing Activities:
Property additions and construction expenditures	(678)	(794)
Proceeds from investments (including derivative collateral posted)	163	139
Purchase of investments (including derivative collateral posted)	(202)	(112)
Payments for (Proceeds from) Hedge, Investing Activities	0	43
Payments for Interest Rate Contract Hedge Investing Activities	(34)	(49)
Net Cash Used in Investing Activities	(751)	(773)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	294	451
Repayments of Long-term Debt	(12)	(248)
Dividends	(190)	(174)
Contributions from parent	82	285
Short-term borrowings, net	110	(139)
Short-term borrowings-affiliate,net	(7)	(10)
Net Cash Provided From Financing Activities	277	165
Net (Decrease) Increase in Cash and Cash Equivalents	(50)	(34)
Cash and Cash Equivalents, January 1	92	51
Cash and Cash Equivalents, September 30	42	17
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	162	160
Cash paid for-Income taxes	143	67
Noncash Investing and Financing Activities:
Accrued construction expenditures	94	89
Capital Lease Obligations Incurred	4	3
Noncash or Part Noncash Acquisition, Value of Assets Acquired	$ 0	$ 98

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RATE AND OTHER REGULATORY MATTERS (Details 2) (USD $) In Millions, unless otherwise specified	9 Months Ended		3 Months Ended	9 Months Ended	12 Months Ended						12 Months Ended										9 Months Ended							9 Months Ended										9 Months Ended													9 Months Ended												9 Months Ended		9 Months Ended		9 Months Ended						3 Months Ended	9 Months Ended	12 Months Ended	9 Months Ended		9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014 SCEG	Sep. 30, 2014 SCEG	May 01, 2015 SCEG	Dec. 31, 2013 SCEG	Dec. 31, 2012 SCEG	Mar. 31, 2014 SCEG	Mar. 31, 2013 SCEG	Mar. 31, 2012 SCEG	Dec. 31, 2013 PSNC Energy [Member]	Sep. 30, 2014 PSNC Energy [Member]	Sep. 30, 2014 Asset Retirement Obligation Costs [Member]	Dec. 31, 2013 Asset Retirement Obligation Costs [Member]	Sep. 30, 2014 Asset Retirement Obligation Costs [Member] SCEG	Dec. 31, 2013 Asset Retirement Obligation Costs [Member] SCEG	Sep. 30, 2014 Deferred Income Tax Charges [Member]	Dec. 31, 2013 Deferred Income Tax Charges [Member]	Sep. 30, 2014 Deferred Income Tax Charges [Member] SCEG	Dec. 31, 2013 Deferred Income Tax Charges [Member] SCEG	Sep. 30, 2014 Storm damage reserve [Member]	Dec. 31, 2013 Storm damage reserve [Member]	Sep. 30, 2014 Storm damage reserve [Member] SCEG	Sep. 30, 2014 Monetization bankruptcy claim [Member]	Dec. 31, 2013 Monetization bankruptcy claim [Member]	Sep. 30, 2014 Planned major maintenance [Member]	Dec. 31, 2013 Planned major maintenance [Member]	Sep. 30, 2014 Planned major maintenance [Member] SCEG	Sep. 30, 2014 Deferred gains on interest rate derivatives [Member]	Dec. 31, 2013 Deferred gains on interest rate derivatives [Member]	Sep. 30, 2014 Deferred gains on interest rate derivatives [Member] SCEG	Sep. 30, 2014 Franchise agreement Costs [Member]	Dec. 31, 2013 Franchise agreement Costs [Member]	Sep. 30, 2014 Franchise agreement Costs [Member] SCEG	Dec. 31, 2013 Franchise agreement Costs [Member] SCEG	Sep. 30, 2014 Deferred Losses On Interest Rate Derivatives [Member]	Dec. 31, 2013 Deferred Losses On Interest Rate Derivatives [Member]	Sep. 30, 2014 Deferred Losses On Interest Rate Derivatives [Member] SCEG	Dec. 31, 2013 Deferred Losses On Interest Rate Derivatives [Member] SCEG	Sep. 30, 2014 Deferred Pollution Control Cost [Member]	Dec. 31, 2013 Deferred Pollution Control Cost [Member]	Dec. 31, 2013 Deferred Pollution Control Cost [Member] SCEG	Sep. 30, 2014 Regulatory Clause Revenues, under-recovered [Member]	Dec. 31, 2013 Regulatory Clause Revenues, under-recovered [Member]	Sep. 30, 2014 Regulatory Clause Revenues, under-recovered [Member] SCEG	Dec. 31, 2013 Regulatory Clause Revenues, under-recovered [Member] SCEG	Sep. 30, 2014 Planned major maintenance [Member]	Dec. 31, 2013 Planned major maintenance [Member]	Sep. 30, 2014 Planned major maintenance [Member] SCEG	Dec. 31, 2013 Planned major maintenance [Member] SCEG	Sep. 30, 2014 Asset Retirement Obligation Costs [Member]	Dec. 31, 2013 Asset Retirement Obligation Costs [Member]	Sep. 30, 2014 Asset Retirement Obligation Costs [Member] SCEG	Dec. 31, 2013 Asset Retirement Obligation Costs [Member] SCEG	Sep. 30, 2014 unrecovered plant [Member]	Dec. 31, 2013 unrecovered plant [Member]	Sep. 30, 2014 unrecovered plant [Member] SCEG	Dec. 31, 2013 unrecovered plant [Member] SCEG	Sep. 30, 2014 Demand Side Management programs [Member]	Dec. 31, 2013 Demand Side Management programs [Member]	Sep. 30, 2014 Demand Side Management programs [Member] SCEG	Dec. 31, 2013 Demand Side Management programs [Member] SCEG	Sep. 30, 2014 Deferred Income Tax Charges [Member]	Dec. 31, 2013 Deferred Income Tax Charges [Member]	Sep. 30, 2014 Deferred Income Tax Charges [Member] SCEG	Dec. 31, 2013 Deferred Income Tax Charges [Member] SCEG	Sep. 30, 2014 Environmental Restoration Costs [Member]	Dec. 31, 2013 Environmental Restoration Costs [Member]	Sep. 30, 2014 Environmental Restoration Costs [Member] SCEG	Dec. 31, 2013 Environmental Restoration Costs [Member] SCEG	Sep. 30, 2014 Pension Costs [Member]	Dec. 31, 2013 Pension Costs [Member]	Dec. 31, 2012 Pension Costs [Member] SCEG	Sep. 30, 2014 Pension Costs [Member] SCEG	Dec. 31, 2013 Pension Costs [Member] SCEG	Sep. 30, 2014 Other Regulatory Assets [Member]	Dec. 31, 2013 Other Regulatory Assets [Member]	Sep. 30, 2014 Other Regulatory Assets [Member] SCEG	Dec. 31, 2013 Other Regulatory Assets [Member] SCEG
Regulatory Assets
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM																					$ 5.0
Regulatory Asset Recovery Assessments					12
Public Utilities, Rate Calculation Basis				12-month rolling average							12
Net Lost Revenues associated with DSM programs				6.6
Reduction to DSM Program costs deferred				6.6
Fuel Costs				10.3
Undercollected balance fuel						46
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates				0.60%			2.10%
Regulatory Liabilities	857	966	615	615		732	732						719	695	509	495	22	24	17	19	6	27	6	27	29	0	10	0	83	181	83
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates				2.5																	2.5
Storm reserve applied to offset storm damage costs																					16.2
Carrying costs on deferred income tax assets			1.6	4.1
Derivative, Gain on Derivative				17.8
Storm Damage Reserve Cost Applied				5.0
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates				2.80%		2.90%	2.30%
Public Utilities Increase (Decrease) in Retail Electric Rates Approved under BLRA				66.2		67.2	52.1
Demand Side Management Program Costs, Noncurrent								15.4	16.9	19.6
MPG enviromental remediatio																																																																			26
Regulatory Noncurrent Asset, Amortization Period																																						30													90												70		70								30	12	14	33		50
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs				100																	100
Public Utilities Base Fuel under Collected Balance Recovery Period	12			12
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority																																																																									63	14
Regulatory Assets, Noncurrent	1,564.0	1,360.0	1,506.0	1,506.0		1,303.0						1.1																				27.0	31.0	27.0	31.0	318.0	124.0	318.0	124.0	36.0	37.0	37.0	38.0	18.0	38.0	18.0	7.0	0	7.0	0	378.0	368.0	359.0	350.0	139.0	145.0	139.0	145.0	53.0	51.0	53.0	51.0	254.0	259.0	250.0	256.0	40.0	41.0	36.0	37.0	222.0	238.0		201.0	215.0	52.0	48.0	42.0	39.0
Demand side management recovery period				10
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net				5.0
Reduction to Net Lost Revenues from DSM programs				25.00%
Public Utilities changes in Retail Natural Gas Rates Approved under RSA				2.6			7.5
Amounts Recovered through Electric Rates to offset Turbine Expense																												18.4
Amounts Recovered Through Electric Rates to offset Nuclear Related Outage Costs				$ 17.2
Public Utilities, Authorized Allowable Return on Common Equity, Percentage				11.00%

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DERIVATIVE FINANCIAL INSTRUMENTS (Details 3) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Gain (Loss) on Derivatives
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant	insignificant
Effect of Cash Flow Hedges on Statement of Income
Other Comprehensive Income (Loss), Unrealized Gain (Loss) On Derivatives Arising During Period, Net of Tax	$ (2)	$ (1)	$ (3)	$ 3
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	(2)	(2)	(1)	(7)
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	69.0		69.0		26.8
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	117.0		117.0		0
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	187.0		187.0		25.2
Cashcollateralrequestedfromcounterparty	0		0		34.1
Derivative, net asset position	0		0		34.1
LetterofCreditAvailableCommodityDerivatives,assetposition	5.0		5.0		6.0
Commodity Derivative, net asset position	6.0		6.0		6.0
Interest Rate Contract
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(1)	19	(5)	115
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	(1)	(1)	(2)	(2)
Effect of Cash Flow Hedges on Statement of Income
Other Comprehensive Income (Loss), Unrealized Gain (Loss) On Derivatives Arising During Period, Net of Tax	0	0	(4)	4
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	2	2	5	5
Commodity Contract
Effect of Cash Flow Hedges on Statement of Income
Other Comprehensive Income (Loss), Unrealized Gain (Loss) On Derivatives Arising During Period, Net of Tax	(2)	(1)	1	(1)
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	0	0	(4)	2
SCEG
Gain (Loss) on Derivatives
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant	insignificant
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	40.1		40.1		1.5
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	118.6		118.6		0
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	158.6		158.6		1.0
Cashcollateralrequestedfromcounterparty	0		0		31.7
Derivative, net asset position	0		0		31.7
SCEG | Interest Rate Contract
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(1)	19	(5)	115
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	(1)	(1)	(2)	(2)
GasPurchaseforResale [Member] | Commodity Contract
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred			insignificant
Interest Expense [Member] | Interest Rate Contract
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred			(6.3)
Not Designated as Hedging Instrument [Member] | Interest Rate Contract
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred			9.6
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	5		60
Effect of Cash Flow Hedges on Statement of Income
Other Comprehensive Income (Loss), Unrealized Gain (Loss) On Derivatives Arising During Period, Net of Tax	(35)		(220)
Not Designated as Hedging Instrument [Member] | SCEG | Interest Rate Contract
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred			9.6
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	5		60
Effect of Cash Flow Hedges on Statement of Income
Other Comprehensive Income (Loss), Unrealized Gain (Loss) On Derivatives Arising During Period, Net of Tax	$ (35)		$ (220)

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CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Assets
Utility Plant In Service	$ 12,442	$ 12,213
Accumulated Depreciation and Amortization	(4,150)	(4,011)
Construction Work in Progress	3,232	2,724
Plant to be Retired, Net	167	177
Nuclear Fuel, Net of Accumulated Amortization	282	310
Goodwill, Net of Writedown of $230	230	230
Utility Plant, Net	12,203	11,643
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	314	317
Assets held in trust, net-nuclear decommissioning	109	101
Other investments	88	86
Nonutility Property and Investments, Net	511	504
Current Assets:
Cash and cash equivalents	82	136
Receivables, net of allowance for uncollectible accounts	690	802
Inventories (at average cost):
Fuel	213	232
Materials and supplies	143	131
Prepayments and other	231	120
Total Current Assets	1,359	1,421
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	1,564.0	1,360.0
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	55	47
Other	179	189
Total Deferred Debits and Other Assets	1,798	1,596
Total	15,871	15,164
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,355	2,280
Retained Earnings, Unappropriated	2,654	2,444
Accumulated Other Comprehensive Income (Loss), Net of Tax	(61)	(60)
Common equity	4,948	4,664
Long-term Debt, Excluding Current Maturities	5,681	5,395
Total Capitalization	10,629	10,059
Current Liabilities:
Short-term borrowings	487	376
Current portion of long-term debt	52	54
Accounts payable	387	425
Customer deposits and customer prepayments	96	88
Taxes accrued	137	206
Interest accrued	79	82
Dividends declared	72	69
Derivative financial instruments	113	8
Other	113	134
Total Current Liabilities	1,536	1,442
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,781	1,703
Deferred investment tax credits	29	32
Asset retirement obligations	592	576
Pension and other postretirement benefits	224	227
Regulatory Liabilities	857	966
Other	223	159
Total Deferred Credits and Other Liabilities	3,706	3,663
Commitments and Contingencies (Note 9)
Total	15,871	15,164
SCEG
Assets
Utility Plant In Service	10,554	10,378
Accumulated Depreciation and Amortization	(3,618)	(3,499)
Construction Work in Progress	3,143	2,682
Plant to be Retired, Net	167	177
Nuclear Fuel, Net of Accumulated Amortization	282	310
Utility Plant, Net	10,528	10,048
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	70	69
Assets held in trust, net-nuclear decommissioning	109	101
Other investments	2	3
Nonutility Property and Investments, Net	181	173
Current Assets:
Cash and cash equivalents	42	92
Receivables, net of allowance for uncollectible accounts	511	486
Due from Affiliate, Current	27.0	19.0
Inventories (at average cost):
Fuel	127	132
Materials and supplies	128	120
Prepayments and other	104	80
Total Current Assets	939	929
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	1,506.0	1,303.0
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	103	96
Other	142	151
Total Deferred Debits and Other Assets	1,751	1,550
Total	13,399	12,700
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,561	2,479
Retained Earnings, Unappropriated	2,078	1,896
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3)	(3)
Common equity	4,636	4,372
Stockholders' Equity Attributable to Noncontrolling Interest	121	117
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	4,757	4,489
Long-term Debt, Excluding Current Maturities	4,298	4,007
Total Capitalization	9,055	8,496
Current Liabilities:
Short-term borrowings	361	251
Current portion of long-term debt	46	48
Accounts payable	223	241
Due to Affiliate, Current	116.0	117.0
Customer deposits and customer prepayments	58	56
Taxes accrued	153	223
Interest accrued	58	64
Dividends declared	69	62
Derivative financial instruments	104	1
Other	58	71
Total Current Liabilities	1,246	1,134
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,585	1,509
Deferred investment tax credits	29	32
Asset retirement obligations	562	547
Pension and other postretirement benefits	169	173
Regulatory Liabilities	615	732
Other	138	77
Total Deferred Credits and Other Liabilities	3,098	3,070
Commitments and Contingencies (Note 9)
Total	$ 13,399	$ 12,700

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SEGMENT OF BUSINESS INFORMATION (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	$ 739	$ 704	$ 2,027	$ 1,898
Intersegment Revenue	0	0	0	0
Operating Income	269	255	772	738
Regulated Operating Revenue, Gas	132	128	740	667
Regulated and Unregulated Operating Revenue	1,121	1,051	3,736	3,378
Income Available to Common Shareholders	144	131	433	368
Segment Assets	15,871		15,871		15,164
Electric Operations
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	739	704	2,027	1,898
Intersegment Revenue	1	2	5	6
Operating Income	275	257	616	588
Segment Assets	9,898		9,898		9,488
Gas Distribution
Segment Reporting Information [Line Items]
Intersegment Revenue	0	0	0	0
Operating Income	(6)	(6)	98	94
Regulated and Unregulated Operating Revenue	127	123	728	657
Segment Assets	2,365		2,365		2,340
Retail Gas Marketing
Segment Reporting Information [Line Items]
Intersegment Revenue	0	0	0	0
Regulated and Unregulated Operating Revenue	68	67	367	325
Income Available to Common Shareholders	(3)	(2)	16	16
Segment Assets	121		121		172
Energy Marketing [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue	47	44	154	133
Regulated and Unregulated Operating Revenue	182	152	602	488
Income Available to Common Shareholders	(2)	1	5	5
Segment Assets	110		110		133
All Other [member]
Segment Reporting Information [Line Items]
Intersegment Revenue	103	95	317	303
Operating Income	7	8	21	22
Regulated and Unregulated Operating Revenue	9	11	27	30
Income Available to Common Shareholders	(5)	(3)	(3)	(2)
Segment Assets	1,333		1,333		1,378
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Intersegment Revenue	(151)	(141)	(476)	(442)
Operating Income	(7)	(4)	37	34
Regulated and Unregulated Operating Revenue	(4)	(6)	(15)	(20)
Income Available to Common Shareholders	154	135	415	349
Segment Assets	2,044		2,044		1,653
SCEG
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	740	706	2,032	1,903
Operating Income	272	255	656	625
Regulated Operating Revenue, Gas	72	70	337	297
Net Income (Loss) Attributable to Parent	154	136	374	311
Segment Assets	13,399		13,399		12,700
Regulated Operating Revenue	812	776	2,369	2,200
SCEG | Electric Operations
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	740	706	2,032	1,903
Operating Income	274	257	616	588
Segment Assets	9,898		9,898		9,488
SCEG | Gas Distribution
Segment Reporting Information [Line Items]
Operating Income	(2)	(2)	40	37
Regulated Operating Revenue, Gas	72	70	337	297
Segment Assets	709		709		686
SCEG | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Operating Income	0	0	0	0
Net Income (Loss) Attributable to Parent	154	136	374	311
Segment Assets	2,792		2,792		2,526
Regulated Operating Revenue	$ 0	$ 0	$ 0	$ 0

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant	insignificant
Net Income (Loss) Attributable to Parent [Abstract]
Net Income	$ 144	$ 131	$ 433	$ 368
Other Comprehensive Income (Loss)
Unrealized gains (losses) on cash flow hedging activities arising during period	(2)	(1)	(3)	3
(Gains) Losses on cash flow hedging activities reclassified to net income	2	2	1	7
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax		4		4
Other Comprehensive Income (Loss)	1	6	(1)	15
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax	1	1	1	1
SCEG
Reclassifcations of deferred employee benefit costs			not significant
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant	insignificant
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	157	139	383	319
Other Comprehensive Income (Loss)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax		1		1
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	157	140	383	320
Genco
Other Comprehensive Income (Loss)
Less comprehensive income attributable to noncontrolling interest	3	3	9	8
SCE&G (including Fuel Company)
Net Income (Loss) Attributable to Parent [Abstract]
Net Income			$ 374	$ 311

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LONG-TERM AND SHORT-TERM DEBT (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended					9 Months Ended				6 Months Ended									3 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Mar. 31, 2013	Sep. 30, 2014 Credit Suisse AG, Cayman Islands Branch (Member)	Sep. 30, 2014 Branch Banking Trust Company [Member]	Sep. 30, 2014 SCE&G (including Fuel Company)	Dec. 31, 2013 SCE&G (including Fuel Company)	Sep. 30, 2014 SCE&G (including Fuel Company) Credit Suisse AG, Cayman Islands Branch (Member)	Sep. 30, 2014 SCE&G (including Fuel Company) Branch Banking Trust Company [Member]	Jun. 30, 2014 SCEG	Sep. 30, 2014 SCEG	Dec. 31, 2013 SCEG	Sep. 30, 2014 SCEG Credit Suisse AG, Cayman Islands Branch (Member)	Sep. 30, 2014 SCEG Branch Banking Trust Company [Member]	Sep. 30, 2014 PSNC Energy [Member]	Dec. 31, 2013 PSNC Energy [Member]	Sep. 30, 2014 Fuel Company	Mar. 31, 2013 Bonds [Member]	Mar. 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]
Proceeds from Issuance of First Mortgage Bond										$ 300
Debt Instrument, Increase, Additional Borrowings																			39.5	14.7
Debt Instrument, Interest Rate, Stated Percentage			3.63%															5.20%			4.00%
Debt Instrument, Decrease, Repayments																				56.9
Line of Credit Facility, Maximum Borrowing Capacity	1,800					1,400	1,400				1,200				100	100	500
Commercial Paper Maximum Term	Outstanding commercial paper (270 or fewer days)					Outstanding commercial paper (270 or fewer days)
Commercial Paper						(361)	(251)								0	0
Debt, Weighted Average Interest Rate						0.28%	0.27%								0.00%	0.00%
Letters of Credit Outstanding, Amount						0.3	(0.3)								0	0
Line of Credit Facility, Remaining Borrowing Capacity						1,039	1,149								100	100
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%	8.90%			8.90%	6.30%				8.90%	8.90%
Number of other banks (in entities)	2										2
Long-term Debt, Current Maturities	52	54									46	48
Debt Instrument, Face Amount											$ 67.8
Debt Instrument, Interest Rate Terms										.045

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

9 Months Ended

Sep. 30, 2014

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:     

	Third Quarter		Year to Date
Millions	2014	2013	2014	2013
Weighted Average Shares Outstanding - Basic	142.1	140.1	141.6	138.0
Effect of dilutive equity forward shares	—	—	—	0.6
Weighted Average Shares - Diluted	142.1	140.1	141.6	138.6

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LONG-TERM AND SHORT-TERM DEBT (Details 2) (USD $)	9 Months Ended																																	9 Months Ended									3 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Mar. 31, 2013	Sep. 30, 2014 Wells Fargo Bank, National Association (Member)	Sep. 30, 2014 Bank of America, N.A. (Member)	Sep. 30, 2014 Morgan Stanly Bank, N.A. (Member)	Sep. 30, 2014 Branch Banking Trust Company [Member]	Sep. 30, 2014 Credit Suisse AG, Cayman Islands Branch (Member)	Sep. 30, 2014 JPMorgan Chase Bank, N.A. (Member)	Sep. 30, 2014 Mizuho Corporate Bank, Ltd (Member)	Sep. 30, 2014 TD Bank, N.A. (Member)	Sep. 30, 2014 UBS Loan Finance LLC (Member)	Sep. 30, 2014 Deutsche Bank AG New York Branch [Member] [Member]	Sep. 30, 2014 Union Bank, N.A. (Member)	Sep. 30, 2014 US Bank National Association (Member)	Sep. 30, 2014 Two other banks [Domain]	Sep. 30, 2014 SCEG	Dec. 31, 2013 SCEG	Sep. 30, 2014 SCEG Wells Fargo Bank, National Association (Member)	Sep. 30, 2014 SCEG Bank of America, N.A. (Member)	Sep. 30, 2014 SCEG Morgan Stanly Bank, N.A. (Member)	Sep. 30, 2014 SCEG Branch Banking Trust Company [Member]	Sep. 30, 2014 SCEG Credit Suisse AG, Cayman Islands Branch (Member)	Sep. 30, 2014 SCEG JPMorgan Chase Bank, N.A. (Member)	Sep. 30, 2014 SCEG Mizuho Corporate Bank, Ltd (Member)	Sep. 30, 2014 SCEG TD Bank, N.A. (Member)	Sep. 30, 2014 SCEG UBS Loan Finance LLC (Member)	Sep. 30, 2014 SCEG Deutsche Bank AG New York Branch [Member] [Member]	Sep. 30, 2014 SCEG Union Bank, N.A. (Member)	Sep. 30, 2014 SCEG US Bank National Association (Member)	Sep. 30, 2014 SCEG Two other banks [Domain]	Sep. 30, 2014 Parent Company [Member]	Dec. 31, 2013 Parent Company [Member]	Sep. 30, 2014 SCE&G (including Fuel Company)	Dec. 31, 2013 SCE&G (including Fuel Company)	Sep. 30, 2014 SCE&G (including Fuel Company) Wells Fargo Bank, National Association (Member)	Sep. 30, 2014 SCE&G (including Fuel Company) Branch Banking Trust Company [Member]	Sep. 30, 2014 SCE&G (including Fuel Company) Credit Suisse AG, Cayman Islands Branch (Member)	Sep. 30, 2014 Fuel Company	Sep. 30, 2014 PSNC Energy	Dec. 31, 2013 PSNC Energy	Mar. 31, 2013 Bonds [Member]	Mar. 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]
Long Term Contract for Nuclear Fuel Purchase	$ 100,000,000
Due to Affiliate, Current																	116,000,000	117,000,000
Debt Instruments [Abstract]
Debt Instrument, Increase, Additional Borrowings																																											39,500,000	14,700,000
Debt Instrument, Interest Rate, Stated Percentage			3.63%																																							5.20%			4.00%
Face value of Industrial Revenue Bonds issued, proceeds of which were availed as loan																	67,800,000
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity	1,800,000,000																1,200,000,000															300,000,000	300,000,000	1,400,000,000	1,400,000,000				500,000,000	100,000,000	100,000,000
Commercial Paper																																127,000,000	125,000,000	361,000,000	251,000,000					0	0
Commercial paper, weighted average interest rate (as a percent)																																0.35%	0.39%	0.28%	0.27%					0.00%	0.00%
Commercial Paper Maximum Term	Outstanding commercial paper (270 or fewer days)																																	Outstanding commercial paper (270 or fewer days)
Letters of credit supported by LOC																																3,000,000	3,000,000	(300,000)	300,000					0	0
Line of Credit Facility, Remaining Borrowing Capacity																																170,000,000	172,000,000	1,039,000,000	1,149,000,000					100,000,000	100,000,000
3 year credit agreement																	200,000,000																	200,000,000
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				10.70%	10.70%	10.70%	8.90%	8.90%	8.90%	8.90%	8.90%	8.90%	6.30%	6.30%	6.30%	6.00%			10.70%	10.70%	10.70%	8.90%	8.90%	8.90%	8.90%	8.90%	8.90%	6.30%	6.30%	6.30%	6.00%					10.70%	6.30%	8.90%
Long-term Line of Credit																																		1,400,000,000
Number of other banks (in entities)	2																2
Related Party Transaction, Due from (to) Related Party, Current	20,800,000	27,300,000
Repayments of Debt																																												$ 56,900,000

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COMMON EQUITY (Tables)

9 Months Ended

Sep. 30, 2014

Schedule of Capitalization, Equity [Line Items]

Schedule of Stockholders Equity [Table Text Block]

						Accumulated Other Comprehensive Income (Loss)
Millions of dollars	Common Stock		Retained Earnings			Gains (Losses) on Cash Flow Hedges			Deferred Employee Benefit Plans			Total AOCI			Total Common Equity
Balance as of January 1, 2014	$	2,280	$	2,444		$	(52	)	$	(8	)	$	(60	)	$	4,664
Net Income			433												433
Other Comprehensive Income (Loss):
Losses arising during the period						(3		)	—			(3		)	(3		)
Losses/amortization reclassified from AOCI						1			1			2			2
Total Comprehensive Income (Loss)			433			(2		)	1			(1		)	432
Issuance of Common Stock	75														75
Dividends Declared			(223		)										(223		)
Balance as of September 30, 2014	$	2,355	$	2,654		$	(54	)	$	(7	)	$	(61	)	$	4,948
Balance as of January 1, 2013	$	1,983	$	2,257		$	(70	)	$	(16	)	$	(86	)	$	4,154
Net Income			368												368
Other Comprehensive Income:
Gains arising during the period						3			4			7			7
Losses/amortization reclassified from AOCI						7			1			8			8
Total Comprehensive Income			368			10			5			15			383
Issuance of Common Stock	273														273
Dividends Declared			(212		)										(212		)
Balance as of September 30, 2013	$	2,256	$	2,413		$	(60	)	$	(11	)	$	(71	)	$	4,598

Reclassifications from Other Comprehensive Income [Table Text Block]

SCEG

Schedule of Capitalization, Equity [Line Items]

Schedule of Stockholders Equity [Table Text Block]

Changes in common equity during the nine months ended September 30, 2014 and 2013 were as follows:

Millions of dollars	Common Stock		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total Equity
Balance at January 1, 2014	$	2,479	$	1,896		$	(3	)	$	117		$	4,489
Earnings available to common shareholder			374						9			383
Deferred cost of employee benefit plans						—						—
Total Comprehensive Income			374			—			9			383
Capital contributions from parent	82											82
Cash dividend declared			(192		)				(5		)	(197		)
Balance at September 30, 2014	$	2,561	$	2,078		$	(3	)	$	121		$	4,757
Balance at January 1, 2013	$	2,167	$	1,766		$	(4	)	$	114		$	4,043
Earnings available to common shareholder			311						8			319
Deferred cost of employee benefit plans						1						1
Total Comprehensive Income			311			1			8			320
Capital contributions from parent	285											285
Cash dividend declared			(190		)				(5		)	(195		)
Balance at September 30, 2013	$	2,452	$	1,887		$	(3	)	$	117		$	4,453

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Other Comprehensive (Income) Loss, Pension and Other Postretirment Benefit Plans, Remeasurement and Curtailment Adjustment, Tax	$ 0	$ 2,000,000	$ 0	$ 2,000,000
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(1,000,000)	0	(2,000,000)	2,000,000
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	$ 1,000,000	$ 1,000,000	$ 0	$ 4,000,000

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Common Stock, Shares, Outstanding	142.2	140.7
Public Utilities, Property, Plant and Equipment, Net	$ 12,203	$ 11,643
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	156	150
Allowance for Doubtful Accounts Receivable, Current	6	6
Assets, Current	1,359	1,421
Regulated Entity, Other Assets, Noncurrent	1,798	1,596
PSNC Energy [Member]
Write-down, Goodwill	230	230
SCEG
Common Stock, Shares, Outstanding	40.3	40.3
Public Utilities, Property, Plant and Equipment, Net	10,528	10,048
Allowance for Doubtful Accounts Receivable, Current	4	3
Assets, Current	939	929
Regulated Entity, Other Assets, Noncurrent	1,751	1,550
SCEG | Variable Interest Entity, Primary Beneficiary [Member]
Public Utilities, Property, Plant and Equipment, Net	687	720
Assets, Current	124	147
Regulated Entity, Other Assets, Noncurrent	$ 43	$ 35

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EMPLOYEE BENEFIT PLANS

9 Months Ended

Sep. 30, 2014

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	2014			2013			2014			2013
Three months ended September 30,
Service cost	$	5.0		$	5.1		$	0.9		$	1.2
Interest cost	9.9			9.5			2.8			2.8
Expected return on assets	(16.4		)	(15.1		)	—			—
Prior service cost amortization	1.1			1.5			0.1			0.1
Charge due to curtailment	—			9.9			—			—
Amortization of actuarial losses	0.9			3.5			(0.2		)	0.8
Net periodic benefit cost	$	0.5		$	14.4		$	3.6		$	4.9

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2014			2013			2014		2013
Nine months ended September 30,
Service cost	$	15.0		$	16.9		$	3.4	$	4.4
Interest cost	30.3			28.4			9.0		8.3
Expected return on assets	(50.0		)	(45.8		)	—		—
Prior service cost amortization	3.1			4.9			0.3		0.5
Charge due to curtailment	—			9.9			—		—
Transition obligation amortization	—			—			—		0.3
Amortization of actuarial losses	3.5			14.4			—		2.5
Net periodic benefit cost	$	1.9		$	28.7		$	12.7	$	16.0

No significant contribution to the pension trust is expected for the foreseeable future, nor is a limitation on benefit payments expected to apply. SCE&G recovers current pension costs through either a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations. Certain pension costs arising prior to 2013 were deferred for future recovery under regulatory orders as discussed 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 the majority of 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	2014			2013			2014			2013
Three months ended September 30,
Service cost	$	4.0		$	4.1		$	0.7		$	1.0
Interest cost	8.4			8.0			2.3			2.1
Expected return on assets	(13.9		)	(12.7		)	—			—
Prior service cost amortization	0.9			1.3			—			0.1
Charge due to curtailment	—			8.4			—			—
Amortization of actuarial losses	0.8			3.0			(0.2		)	0.7
Net periodic benefit cost	$	0.2		$	12.1		$	2.8		$	3.9

Nine months ended September 30,
Service cost	$	12.0		$	13.7		$	2.7	$	3.5
Interest cost	25.6			24.0			7.1		6.5
Expected return on assets	(42.2		)	(38.7		)	—		—
Prior service cost amortization	2.6			4.1			0.2		0.4
Charge due to curtailment	—			8.4			—		—
Amortization of actuarial losses	3.0			12.2			—		2.0
Net periodic benefit cost	$	1.0		$	23.7		$	10.0	$	12.4

No significant contribution to the pension trust is expected for the foreseeable future, nor is a limitation on benefit payments expected to apply. SCE&G recovers current pension costs through either a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations. Certain pension costs arising prior to 2013 were deferred for future recovery under regulatory orders as discussed in Note 2.

XML

Document and Entity Information Document	9 Months Ended
	Sep. 30, 2014	Oct. 31, 2014
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	Sep. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		142,550,214
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	Sep. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		40,296,147

XML

COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2014

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 SCE&G's nuclear power plant. Price-Anderson provides funds up to $13.6 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 $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 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 $84.8 million per incident, but not more than $12.6 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 insurance 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 resulting from an event of nuclear origin. 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 $43.5 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, 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.

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 current ownership share in the New Units is 55%. Under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, will acquire an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and will acquire the final 2% no later than the second anniversary of such commercial operation date. Under the terms of the agreement SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost of the percentage conveyed as of the date of conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction will not affect the payment obligations between the parties during construction for the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA.

Under the BLRA, the SCPSC has approved, among other things, the milestone schedule and capital costs estimates schedule for the New Units. The effect of this approval is that it constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. The BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Such annual rate changes are described in Note 2.

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 have impacted the project budget and schedule. SCE&G expects to resolve all disputes through both the informal and formal procedures and anticipates that any costs that arise through such dispute resolution processes, as well as other costs identified from time to time, will be recoverable through rates.

In November 2012, the SCPSC approved a petition by SCE&G under the BLRA for an updated milestone schedule and additional updated capital costs for the New Units. In addition, the SCPSC 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 known claims by the Consortium 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. Immediately thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its order, and 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, contending that the SCPSC erred in granting approval of the updated capital costs for the New Units. On October 22, 2014, the South Carolina Supreme Court affirmed the SCPSC's order.

The substantial completion dates currently approved by the SCPSC for Units 2 and 3 are March 15, 2017 and May 15, 2018. The SCPSC has also approved an 18-month contingency period beyond each of these dates. As of September 30, 2014, SCE&G's 55% share of the estimated cash outlays (future value, excluding AFC) totaled approximately $5.5 billion for plant and related transmission infrastructure costs, based on historical one-year and five-year escalation rates as required by the SCPSC. As of September 30, 2014, and based on the updated milestone schedule and capital costs schedule approved by the SCPSC in November 2012 (see above), SCE&G estimated such cost will be approximately $500 million for the additional 5% interest being acquired from Santee Cooper.

Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule for fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules have been and remain focus areas of the Consortium, including sub-modules for module CA20, which is part of the auxiliary building, and CA01, which houses components inside the containment vessel. Modules CA20 and CA01, as well as shield building modules, are considered critical path items for both New Units. CA20 was placed on the nuclear island of Unit 2 in May 2014. The delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow it to be ready for placement on the nuclear island of Unit 2 during the first half of 2015.

During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the schedules and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and design resource allocations, procurement, construction work crew efficiencies, and other items. The result will be a revised fully integrated project schedule with timing of specific construction activities along with detailed information on budget, cost and cash flow requirements. While this detailed re-baselining of construction schedules has not been completed, in August 2014, SCE&G received preliminary information in which the Consortium has indicated that the substantial completion of Unit 2 is expected to occur in late 2018 or the first half of 2019 and that the substantial completion of Unit 3 may be approximately 12 months later. These expected substantial completion dates do not reflect all efforts that may be possible to mitigate delay, nor has SCE&G accepted this new schedule.

Also in August 2014, the IRS notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. To the extent that production tax credits are realized, their benefits are expected to be provided to SCE&G's electric customers.

The Consortium has also provided preliminary cost estimates for Units 2 and 3 principally related to delays for non-firm and non-fixed scopes of work to achieve the late 2018 substantial completion date for Unit 2 and a substantial completion date for Unit 3 approximately 12 months later. SCE&G's 55% portion of this preliminary estimate is approximately $660 million. This figure is presented in 2007 dollars and would be subject to escalation. This figure also excludes any owner's cost amounts associated with the delays, which amounts could be significant. Further, this figure does not reflect consideration of the liquidated damages provisions of the EPC Contract which would partly mitigate any such delay-related costs. The Consortium's preliminary schedule and the cost estimate information have not been accepted by SCE&G and are under review. It is anticipated that further study, evaluation and negotiations will occur. SCE&G plans to reevaluate and reschedule its owners cost estimates and cash flow requirements in light of that new schedule when it is finalized. SCE&G anticipates that the revised schedule and cost estimate will be finalized sometime in 2015.

The milestone schedule approved by the SCPSC in November 2012 provides for 146 milestone dates, which are each subject to an 18-month schedule contingency. As of October 31, 2014, 100 milestones have been completed. The completion dates for two of the remaining milestones have been extended beyond their 18-month contingency periods, and it is anticipated that the completion dates for a number of the other remaining milestone dates will also extend beyond their contingency periods. Upon completion of the re-baselining and the finalization of the revised schedule and cost estimate at completion, SCE&G, as provided for under the BLRA, expects to petition the SCPSC for an order to update the BLRA milestone schedule and capital costs estimates schedule. The BLRA provides that the SCPSC shall grant the petition for modification if the record justifies a finding that the change is not the result of imprudence by SCE&G.

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.  SCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the construction and operation of the New Units, and prepared and submitted an integrated response plan for the New Units to the NRC in August 2013. SCE&G cannot predict what additional regulatory or other outcomes may be implemented, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New Units.

Environmental

As part of the President's Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA was directed to issue a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The rule became final on January 8, 2014 and requires 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-fired plants can be constructed without carbon capture and sequestration capabilities. The Company is evaluating the final rule, but does not plan to construct new coal-fired units in the foreseeable future.

The Memorandum also directed the EPA to issue standards, regulations, or guidelines for existing units. On June 2, 2014, the EPA released the Clean Power Plan, a proposal to regulate carbon dioxide emissions from existing units. The proposed rule includes state-specific goals for carbon dioxide emissions, as well as guidelines for states to follow in developing SIPs to achieve those goals. The Company is evaluating the proposed rule which may be revised before it becomes final in June 2015. As currently proposed, states will have from one to three years from the date of any final rule to issue SIPs that will ultimately define the specific compliance methodology that will be applied to existing units in that state. The Company expects that any costs incurred to comply with such requirements will be recoverable through rates.

In 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states 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 Court of Appeals 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. On April 29, 2014, the U. S. Supreme Court reversed the judgment of the Court of Appeals, and CSAPR was remanded to the Court of Appeals for further proceedings consistent with the U. S. Supreme Court opinion. On October 23, 2014, the Court of Appeals granted EPA's June 26, 2014 motion to lift the stay of the CSAPR. EPA's motion asked the court to postpone the CSAPR compliance deadlines by three years, so that CSAPR's Phase 1 emission budgets will apply starting in 2015, and CSAPR's Phase 2 emission budgets will apply in 2017 and subsequent years. Air quality control installations that SCE&G and GENCO have already completed have allowed the Company to comply with the reinstated CAIR and will also allow it to comply with CSAPR. 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 CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule was published in the Federal Register on June 7, 2013, and is expected to be finalized September 30, 2015. The EPA expects compliance within a three to six year time frame as NPDES permits are renewed.

On August 15, 2014, the EPA finalized a rule (effective October 14, 2014) that modifies requirements for existing cooling water intake structures. The Company is conducting studies and is developing or implementing compliance plans for this rule. Congress is also expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones. These provisions, if passed, could have a material impact on the financial condition, results of operations and cash flows of the Company. The Company believes that any additional costs imposed by such regulations, including compliance therewith, would be recoverable through rates.

In response to a federal court order to establish a definite timeline for a CCR rule and subsequent obligation via consent decree, the EPA committed to issue new federal regulations affecting the management and disposal of CCRs, such as ash, by December 19, 2014. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities such as SCE&G and GENCO. While the Company cannot predict how extensive the regulations will be, the Company believes that any additional costs imposed by such regulations would be recoverable through rates.

The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998. The Nuclear Waste Act also imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. To date, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017, and is constructing a dry cask storage facility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1. SCE&G may evaluate other technology as it becomes available. See also Note 2.

The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. In addition, the states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates.

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 through 2017 and will cost an additional $19.5 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 September 30, 2014, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $35.9 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 potentially responsible parties.  PSNC Energy has recorded a liability and associated regulatory asset of approximately $1.1 million, the estimated remaining liability at September 30, 2014. PSNC Energy expects to recover through rates any cost allocable to PSNC Energy arising from the remediation of these sites.

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 SCE&G's nuclear power plant. Price-Anderson provides funds up to $13.6 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 $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 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 $84.8 million per incident, but not more than $12.6 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 insurance 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 resulting from an event of nuclear origin. 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 $43.5 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, 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 Consolidated SCE&G’s results of operations, cash flows and financial position.

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 current ownership share in the New Units is 55%. Under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, will acquire an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and will acquire the final 2% no later than the second anniversary of such commercial operation date. Under the terms of the agreement SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost of the percentage conveyed as of the date of conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction will not affect the payment obligations between the parties during construction for the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA.

Under the BLRA, the SCPSC has approved, among other things, the milestone schedule and capital costs estimates schedule for the New Units. The effect of this approval is that it constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. The BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Such annual rate changes are described in Note 2.

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 have impacted the project budget and schedule. SCE&G expects to resolve all disputes through both the informal and formal procedures and anticipates that any costs that arise through such dispute resolution processes, as well as other costs identified from time to time, will be recoverable through rates.

In November 2012, the SCPSC approved a petition by SCE&G under the BLRA for an updated milestone schedule and additional updated capital costs for the New Units. In addition, the SCPSC 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 known claims by the Consortium 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. Immediately thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its order, and 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, contending that the SCPSC erred in granting approval of the updated capital costs for the New Units. On October 22, 2014, the South Carolina Supreme Court affirmed the SCPSC's order.

The substantial completion dates currently approved by the SCPSC for Units 2 and 3 are March 15, 2017 and May 15, 2018. The SCPSC has also approved an 18-month contingency period beyond each of these dates. As of September 30, 2014, SCE&G's 55% share of the estimated cash outlays (future value, excluding AFC) totaled approximately $5.5 billion for plant and related transmission infrastructure costs, based on historical one-year and five-year escalation rates as required by the SCPSC. As of September 30, 2014, and based on the updated milestone schedule and capital costs schedule approved by the SCPSC in November 2012 (see above), SCE&G estimated such cost will be approximately $500 million for the additional 5% interest being acquired from Santee Cooper.

Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule for fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules have been and remain focus areas of the Consortium, including sub-modules for module CA20, which is part of the auxiliary building, and CA01, which houses components inside the containment vessel. Modules CA20 and CA01, as well as shield building modules, are considered critical path items for both New Units. CA20 was placed on the nuclear island of Unit 2 in May 2014. The delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow it to be ready for placement on the nuclear island of Unit 2 during the first half of 2015.

During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the schedules and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and design resource allocations, procurement, construction work crew efficiencies, and other items. The result will be a revised fully integrated project schedule with timing of specific construction activities along with detailed information on budget, cost and cash flow requirements. While this detailed re-baselining of construction schedules has not been completed, in August 2014, SCE&G received preliminary information in which the Consortium has indicated that the substantial completion of Unit 2 is expected to occur in late 2018 or the first half of 2019 and that the substantial completion of Unit 3 may be approximately 12 months later. These expected substantial completion dates do not reflect all efforts that may be possible to mitigate delay, nor has SCE&G accepted this new schedule.

Also in August 2014, the IRS notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. To the extent that production tax credits are realized, their benefits are expected to be provided to SCE&G's electric customers.

The Consortium has also provided preliminary cost estimates for Units 2 and 3 principally related to delays for non-firm and non-fixed scopes of work to achieve the late 2018 substantial completion date for Unit 2 and a substantial completion date for Unit 3 approximately 12 months later. SCE&G's 55% portion of this preliminary estimate is approximately $660 million. This figure is presented in 2007 dollars and would be subject to escalation. This figure also excludes any owner's cost amounts associated with the delays, which amounts could be significant. Further, this figure does not reflect consideration of the liquidated damages provisions of the EPC Contract which would partly mitigate any such delay-related costs. The Consortium's preliminary schedule and the cost estimate information have not been accepted by SCE&G and are under review. It is anticipated that further study, evaluation and negotiations will occur. SCE&G plans to reevaluate and reschedule its owners cost estimates and cash flow requirements in light of that new schedule when it is finalized. SCE&G anticipates that the revised schedule and cost estimate will be finalized sometime in 2015.

The milestone schedule approved by the SCPSC in November 2012 provides for 146 milestone dates, which are each subject to an 18-month schedule contingency. As of October 31, 2014, 100 milestones have been completed. The completion dates for two of the remaining milestones have been extended beyond their 18-month contingency periods, and it is anticipated that the completion dates for a number of the other remaining milestone dates will also extend beyond their contingency periods. Upon completion of the re-baselining and the finalization of the revised schedule and cost estimate at completion, SCE&G, as provided for under the BLRA, expects to petition the SCPSC for an order to update the BLRA milestone schedule and capital costs estimates schedule. The BLRA provides that the SCPSC shall grant the petition for modification if the record justifies a finding that the change is not the result of imprudence by SCE&G.

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.  SCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the construction and operation of the New Units, and prepared and submitted an integrated response plan for the New Units to the NRC in August 2013. SCE&G cannot predict what additional regulatory or other outcomes may be implemented, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New Units.

Environmental

As part of the President's Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA was directed to issue a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The rule became final on January 8, 2014 and requires 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-fired plants can be constructed without carbon capture and sequestration capabilities. Consolidated SCE&G is evaluating the final rule, but does not plan to construct new coal-fired units in the foreseeable future.

The Memorandum also directed the EPA to issue standards, regulations, or guidelines for existing units. On June 2, 2014, the EPA released the Clean Power Plan, a proposal to regulate carbon dioxide emissions from existing units. The proposed rule includes state-specific goals for carbon dioxide emissions, as well as guidelines for states to follow in developing SIPs to achieve those goals. Consolidated SCE&G is evaluating the proposed rule which may be revised before it becomes final in June 2015. As currently proposed, states will have from one to three years from the date of any final rule to issue SIPs that will ultimately define the specific compliance methodology that will be applied to existing units in that state. Consolidated SCE&G expects that any costs incurred to comply with such requirements will be recoverable through rates.

In 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states 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 Court of Appeals 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. On April 29, 2014, the U. S. Supreme Court reversed the judgment of the Court of Appeals and CSAPR was remanded to the Court of Appeals for further proceedings consistent with the U. S. Supreme Court opinion. On October 23, 2014, the Court of Appeals granted EPA's June 26, 2014 motion to lift the stay of the CSAPR. EPA's motion asked the court to postpone the CSAPR compliance deadlines by three years, so that CSAPR's Phase 1 emission budgets will apply starting in 2015, and CSAPR's Phase 2 emission budgets will apply in 2017 and subsequent years. Air quality control installations that SCE&G and GENCO have already completed have allowed Consolidated SCE&G to comply with the reinstated CAIR and will also allow it to comply with CSAPR.  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 CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule was published in the Federal Register on June 7, 2013, and is expected to be finalized September 30, 2015. The EPA expects compliance within a three to six year time frame as NPDES permits are renewed.

On August 15, 2014, the EPA finalized a rule (effective October 14, 2014) that modifies requirements for existing cooling water intake structures. Consolidated SCE&G is conducting studies and is developing or implementing compliance plans for this rule. Congress is also expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones. These provisions, if passed, could have a material impact on the financial condition, results of operations and cash flows of Consolidated SCE&G. Consolidated SCE&G believes that any additional costs imposed by such regulations, including compliance therewith, would be recoverable through rates.

In response to a federal court order to establish a definite timeline for a CCR rule and subsequent obligation via consent decree, the EPA committed to issue new federal regulations affecting the management and disposal of CCRs, such as ash, by December 19, 2014. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO. While Consolidated SCE&G cannot predict how extensive the regulations will be, Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates.

The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998. The Nuclear Waste Act also imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. To date, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017, and is constructing a dry cask storage facility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1. SCE&G may evaluate other technology as it becomes available. See Note 2.

The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. In addition, the state of South Carolina has similar laws. Consolidated SCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify Consolidated SCE&G that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates.

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 through 2017 and will cost an additional $19.5 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 September 30, 2014, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $35.9 million and are included in regulatory assets.

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Operating Revenues:
Electric Domestic Regulated Revenue	$ 739	$ 704	$ 2,027	$ 1,898
Regulated Operating Revenue, Gas	132	128	740	667
Gas-nonregulated	250	219	969	813
Regulated and Unregulated Operating Revenue	1,121	1,051	3,736	3,378
Operating Expenses [Abstract]
Fuel used in electric generation	212	196	636	570
Purchased power	13	19	54	35
Gas purchased for resale	304	265	1,291	1,076
Other operation and maintenance	169	167	523	513
Depreciation and amortization	96	95	286	282
Other taxes	58	54	174	164
Total Operating Expenses	852	796	2,964	2,640
Operating Income	269	255	772	738
Other Income (Expense):
Other income	18	10	103	36
Other expenses	(12)	(10)	(39)	(32)
Interest Expense	(79)	(74)	(231)	(223)
Allowance for equity funds used during construction	11	9	26	19
Total Other Expense	(62)	(65)	(141)	(200)
Income Before Income Tax Expense	207	190	631	538
Income Tax Expense	63	59	198	170
Net Income	144	131	433	368
Per Common Share Data
Basic Earnings Per Share of Common Stock (in dollars per share)	$ 1.01	$ 0.94	$ 3.06	$ 2.67
Diluted Earnings Per Share of Common Stock (in dollars per share)	$ 1.01	$ 0.94	$ 3.06	$ 2.66
Weighted Average Common Shares Outstanding (millions)
Weighted Average Number of Shares Outstanding, Basic	142.1	140.1	141.6	138.0
Weighted Average Number of Shares Outstanding, Diluted	142.1	140.1	141.6	138.6
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 0.5250	$ 0.5075	$ 1.5750	$ 1.5225
SCEG
Operating Revenues:
Electric Domestic Regulated Revenue	740	706	2,032	1,903
Regulated Operating Revenue, Gas	72	70	337	297
Regulated Operating Revenue	812	776	2,369	2,200
Operating Expenses [Abstract]
Fuel used in electric generation	213	197	640	575
Purchased power	13	19	54	34
Gas purchased for resale	46	45	210	177
Other operation and maintenance	136	132	415	406
Depreciation and amortization	79	78	236	234
Other taxes	53	50	158	149
Total Operating Expenses	540	521	1,713	1,575
Operating Income	272	255	656	625
Other Income (Expense):
Other income	9	0	71	0
Other expenses	(7)	(4)	(19)	(11)
Interest Expense	(57)	(54)	(169)	(163)
Allowance for equity funds used during construction	10	8	22	18
Total Other Expense	(45)	(50)	(95)	(156)
Income Before Income Tax Expense	227	205	561	469
Income Tax Expense	70	66	178	150
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	157	139	383	319
Net Income (Loss) Attributable to Noncontrolling Interest	(3)	(3)	(9)	(8)
Earnings Available to Common Shareholder	154	136	374	311
Weighted Average Common Shares Outstanding (millions)
Dividends, Common Stock, Cash	$ 69	$ 67	$ 197	$ 195

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COMMON EQUITY

9 Months Ended

Sep. 30, 2014

Schedule of Capitalization, Equity [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

COMMON EQUITY

Changes in common equity during the nine months ended September 30, 2014 and 2013 were as follows:

						Accumulated Other Comprehensive Income (Loss)
Millions of dollars	Common Stock		Retained Earnings			Gains (Losses) on Cash Flow Hedges			Deferred Employee Benefit Plans			Total AOCI			Total Common Equity
Balance as of January 1, 2014	$	2,280	$	2,444		$	(52	)	$	(8	)	$	(60	)	$	4,664
Net Income			433												433
Other Comprehensive Income (Loss):
Losses arising during the period						(3		)	—			(3		)	(3		)
Losses/amortization reclassified from AOCI						1			1			2			2
Total Comprehensive Income (Loss)			433			(2		)	1			(1		)	432
Issuance of Common Stock	75														75
Dividends Declared			(223		)										(223		)
Balance as of September 30, 2014	$	2,355	$	2,654		$	(54	)	$	(7	)	$	(61	)	$	4,948
Balance as of January 1, 2013	$	1,983	$	2,257		$	(70	)	$	(16	)	$	(86	)	$	4,154
Net Income			368												368
Other Comprehensive Income:
Gains arising during the period						3			4			7			7
Losses/amortization reclassified from AOCI						7			1			8			8
Total Comprehensive Income			368			10			5			15			383
Issuance of Common Stock	273														273
Dividends Declared			(212		)										(212		)
Balance as of September 30, 2013	$	2,256	$	2,413		$	(60	)	$	(11	)	$	(71	)	$	4,598

Gains and losses on cash flow hedges reclassified during the nine months ended September 30, 2014 resulted in higher interest expense of $5 million and lower cost of gas purchased for resale of $4 million. Such reclassifications during the comparable period in 2013 resulted in higher interest expense of $5 million and higher cost of gas purchased for resale of $2 million.

SCANA had 200 million shares of common stock authorized as of September 30, 2014 and December 31, 2013, of which 142.2 million and 140.7 million were issued and outstanding at September 30, 2014 and December 31, 2013, 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.

SCEG

Schedule of Capitalization, Equity [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

EQUITY

Changes in common equity during the nine months ended September 30, 2014 and 2013 were as follows:

Millions of dollars	Common Stock		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total Equity
Balance at January 1, 2014	$	2,479	$	1,896		$	(3	)	$	117		$	4,489
Earnings available to common shareholder			374						9			383
Deferred cost of employee benefit plans						—						—
Total Comprehensive Income			374			—			9			383
Capital contributions from parent	82											82
Cash dividend declared			(192		)				(5		)	(197		)
Balance at September 30, 2014	$	2,561	$	2,078		$	(3	)	$	121		$	4,757
Balance at January 1, 2013	$	2,167	$	1,766		$	(4	)	$	114		$	4,043
Earnings available to common shareholder			311						8			319
Deferred cost of employee benefit plans						1						1
Total Comprehensive Income			311			1			8			320
Capital contributions from parent	285											285
Cash dividend declared			(190		)				(5		)	(195		)
Balance at September 30, 2013	$	2,452	$	1,887		$	(3	)	$	117		$	4,453

SCE&G had 50 million shares of common stock authorized as of September 30, 2014 and December 31, 2013, 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 September 30, 2014 and December 31, 2013, of which 1,000 shares at a stated value of $100,000 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.

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RATE AND OTHER REGULATORY MATTERS

9 Months Ended

Sep. 30, 2014

Rate Matters [Line Items]

Public Utilities Disclosure [Text Block]

RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric - Cost of Fuel

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 connection with its annual review of base rates for fuel costs, and by order dated April 30, 2013, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC in which SCE&G agreed to reduce its environmental fuel cost component effective with the first billing cycle of May 2013. The order also provided for the accrual of certain debt-related carrying costs on a portion of SCE&G's under-collected balance of fuel costs, and approved SCE&G's total fuel cost component.

By order dated April 29, 2014, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC in which SCE&G agreed to increase its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014.  The SCPSC's order also provided for, among other things, the application of approximately $46 million in deferred gains from the late 2013 settlement of certain interest rate swaps, previously recorded as regulatory liabilities, to reduce the under-collected balance of fuel costs in April 2014 and the accrual of certain debt-related carrying costs on its under-collected balance of base fuel costs during the period May 1, 2014 through April 30, 2015. 

The increase to the base fuel cost component was offset by a reduction in SCE&G’s rate rider related to pension costs, which was approved by the SCPSC in March 2014. The reduction was requested by SCE&G as a result of lower net periodic benefit costs in 2014. See also Note 8.

               The cost of fuel includes amounts paid by SCE&G pursuant to the Nuclear Waste Act for the disposal of spent nuclear fuel.  As a result of a November 2013 decision by the Court of Appeals, the DOE set the Nuclear Waste Act fee to zero effective May 16, 2014.  By order of the SCPSC, the impact of this action will be considered in future cost of fuel rate adjustments.

Electric - Base Rates

In October 2013, SCE&G received an accounting order from the SCPSC directing it to remove from rate base deferred income tax assets arising from capital expenditures related to the New Units and to accrue carrying costs (recorded as a regulatory asset) on those amounts during periods in which they are not included in rate base.  Such carrying costs are determined at SCE&G’s weighted average long-term borrowing rate. During the three and nine months ended September 30, 2014, $1.6 million and $4.1 million, respectively, of such carrying costs were accrued within other income. SCE&G anticipates that when the New Units are placed in service and accelerated tax deprecation is recognized on them, these deferred income tax assets will decline.  When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized.

SCE&G files an IRP with the SCPSC annually which evaluates future electric generation needs based on several factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G's 2012 IRP identified six coal-fired units that SCE&G has retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. Three of these units had been retired by December 31, 2013. The net carrying value of these retired units is recorded in regulatory assets as unrecovered plant and is being amortized over the units' previously estimated remaining useful lives as approved by the SCPSC. See also Note 1.

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

Year	Effective	Amount
2014	First billing cycle of May	$15.4 million
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million

Other activity related to SCE&G’s DSM Programs is as follows:

• In May 2013 the SCPSC ordered the deferral as a regulatory asset of one-half of net lost margin revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014.

• In April 2014 the SCPSC approved SCE&G’s request to (1) recover one-half of the balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2014 and to recover the remaining balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2015, (2) utilize approximately $17.8 million of the gains from the late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of the net lost margin revenues component of SCE&G’s DSM Programs rider, and (3) apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments to the remaining balance of deferred net lost margin revenues as of April 30, 2014, which had been deferred within regulatory assets resulting from the May 2013 order previously described. 

• In addition, in April 2014 the SCPSC, upon recommendation of the ORS, reduced by 25%, or $6.6 million, the amount of net lost margin revenues SCE&G expects to experience over the 12-month period beginning with the first billing cycle of May 2014, and ordered that the $6.6 million be applied to decrease the amount of program costs deferred for recovery. Actual net lost margin revenues not collected in the current DSM Programs rate rider are subject to true up in the following program year.

Electric – BLRA

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 retail electric rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated:

Year	Action			Amount
2014	2.8	%	Increase	$66.2 million
2013	2.9	%	Increase	$67.2 million
2012	2.3	%	Increase	$52.1 million

Gas

SCE&G

The RSA is designed to reduce the volatility of costs charged to customers by allowing for 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
2014	0.6	%	Decrease	$2.6 million
2013	No change			-
2012	2.1	%	Increase	$7.5 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, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual review conducted for the 12-month period ended July 31, 2013 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during the review period were reasonable and prudent. SCE&G's 2014 annual PGA hearing was held on November 6, 2014 and the SCPSC's ruling is pending.

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 September 2014, in connection with PSNC Energy's 2014 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, 2014.

During the third quarter of 2013, the State of North Carolina passed legislation that changed statutes covering gross receipts, sales and use, excise, franchise and income taxes.  On December 6, 2013, the NCUC issued an order notifying utilities that the incremental revenue requirement impact associated with the change in the level of state income tax expense included in each utility’s cost of service would be deemed to be collected on a provisional basis (subject to refund) beginning January 1, 2014. On May 13, 2014, the NCUC issued an order requiring utilities to adjust rates to reflect changes in the state corporate income tax rate and to file a proposal to refund amounts collected on a provisional basis. Pursuant to the order, PSNC Energy lowered its rates effective July 1, 2014, and notwithstanding a subsequent reversal of the NCUC's order, PSNC Energy expects to refund amounts collected on a provisional basis through the normal operation of the Rider D rate mechanism. At September 30, 2014, these amounts were not material.

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 regulatory liabilities which are summarized in the following tables. Other than unrecovered plant, 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	September 30, 2014		December 31, 2013
Regulatory Assets:
Accumulated deferred income taxes	$	254	$	259
Under-collections - electric fuel adjustment clause	38		18
Environmental remediation costs	40		41
AROs and related funding	378		368
Franchise agreements	27		31
Deferred employee benefit plan costs	222		238
Planned major maintenance	7		—
Deferred losses on interest rate derivatives	318		124
Deferred pollution control costs	36		37
Unrecovered plant	139		145
DSM Programs	53		51
Other	52		48
Total Regulatory Assets	$	1,564	$	1,360

Regulatory Liabilities:
Accumulated deferred income taxes	$	22	$	24
Asset removal costs	719		695
Storm damage reserve	6		27
Monetization of bankruptcy claim	27		29
Deferred gains on interest rate derivatives	83		181
Planned major maintenance	—		10
Total Regulatory Liabilities	$	857	$	966

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 sites currently or formerly owned by the Company, and are expected to be recovered over periods of up to approximately 26 years.

ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs related to generation, transmission, distribution and other properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 90 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 is recovering these amounts through cost of service rates through 2021.

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, as well as costs deferred pursuant to specific SCPSC regulatory orders. In connection with a December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are being recovered through utility rates over approximately 30 years. In connection with the October 2013 RSA order, approximately $14 million of deferred pension costs for gas operations are being recovered through utility rates over approximately 14 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 and accrues $18.4 million annually for fossil fueled turbine/generation equipment maintenance, and collects and accrues $17.2 million annually for nuclear-related refueling charges.

Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense over periods up to approximately 50 years except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC. Also, in 2014, as discussed at Rate Matters - Electric - Cost of Fuel and Rate Matters - Electric - Base Rates, certain of these deferred amounts were applied to offset under-collected fuel balances and unrecorded net lost margin revenues related to DSM Programs.

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at certain coal-fired generating plants pursuant to specific regulatory orders.  Such costs are being recovered through utility rates through 2045.

Unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return.

DSM Programs represent deferred costs associated with such programs.  As a result of an April 2014 SCPSC order, deferred costs are currently being recovered over approximately ten years through an approved rate rider.  See Rate Matters - Electric - Base Rates above for details regarding the 2014 filing with the SCPSC regarding recovery of these deferred costs.

Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 33 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. In 2014, $16.2 million of the reserve was applied to offset incremental storm damage costs. Also, as discussed at Rate Matters - Electric - Base Rates, in April 2014 $5.0 million of the reserve was applied to offset unrecovered net lost margin revenues related to DSM Programs.

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 - Cost of Fuel

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 connection with its annual review of base rates for fuel costs, and by order dated April 30, 2013, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC in which SCE&G agreed to reduce its environmental fuel cost component effective with the first billing cycle of May 2013. The order also provided for the accrual of certain debt-related carrying costs on a portion of SCE&G's under-collected balance of fuel costs and approved SCE&G's total fuel cost component.

By order dated April 29, 2014, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC in which SCE&G agreed to increase its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014.  The SCPSC's order also provided for, among other things, the application of approximately $46 million in deferred gains from the late 2013 settlement of certain interest rate swaps, previously recorded as regulatory liabilities, to reduce the under-collected balance of fuel costs in April 2014 and the accrual of certain debt-related carrying costs on its under-collected balance of base fuel costs during the period May 1, 2014 through April 30, 2015. 

The increase to the base fuel cost component was offset by a reduction in SCE&G’s rate rider related to pension costs, which was approved by the SCPSC in March 2014. The reduction was requested by SCE&G as a result of lower net periodic benefit costs in 2014. See also Note 8.

The cost of fuel includes amounts paid by SCE&G pursuant to the Nuclear Waste Act for the disposal of spent nuclear fuel.  As a result of a November 2013 decision by the Court of Appeals, the DOE set the Nuclear Waste Act fee to zero effective May 16, 2014.  By order of the SCPSC, the impact of this action will be considered in future cost of fuel rate adjustments.

Electric - Base Rates

In October 2013, SCE&G received an accounting order from the SCPSC directing it to remove from rate base deferred income tax assets arising from capital expenditures related to the New Units and to accrue carrying costs (recorded as a regulatory asset) on those amounts during periods in which they are not included in rate base.  Such carrying costs are determined at SCE&G’s weighted average long-term borrowing rate. During the three and nine months ended September 30, 2014, $1.6 million and $4.1 million, respectively, of such carrying costs were accrued within other income. SCE&G anticipates that when the New Units are placed in service and accelerated tax deprecation is recognized on them, these deferred income tax assets will decline.  When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized.

SCE&G files an IRP with the SCPSC annually which evaluates future electric generation needs based on several factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G's 2012 IRP identified six coal-fired units that SCE&G has retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. Three of these units had been retired by December 31, 2013. The net carrying value of these retired units is recorded in regulatory assets as unrecovered plant and is being amortized over the units' previously estimated remaining useful lives as approved by the SCPSC. See also Note 1.

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

Year	Effective	Amount
2014	First billing cycle of May	$15.4 million
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million

Other activity related to SCE&G’s DSM Programs is as follows:

• In May 2013 the SCPSC ordered the deferral as a regulatory asset of one-half of net lost margin revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014.

• In April 2014 the SCPSC approved SCE&G’s request to (1) recover one-half of the balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2014 and to recover the remaining balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2015, (2) utilize approximately $17.8 million of the gains from the late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of the net lost margin revenues component of SCE&G’s DSM Programs rider, and (3) apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments, to the remaining balance of deferred net lost margin revenues as of April 30, 2014, which had been deferred within regulatory assets resulting from the May 2013 order previously described. 

• In addition, in April 2014 the SCPSC, upon recommendation of the ORS, reduced by 25%, or $6.6 million, the amount of net lost margin revenues SCE&G expects to experience over the 12-month period beginning with the first billing cycle of May 2014, and ordered that the $6.6 million be applied to decrease the amount of program costs deferred for recovery. Actual net lost margin revenues not collected in the current DSM Programs rate rider are subject to true up in the following program year.

Electric – BLRA

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 retail electric rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated:

Year	Action			Amount
2014	2.8	%	Increase	$66.2 million
2013	2.9	%	Increase	$67.2 million
2012	2.3	%	Increase	$52.1 million

Gas

The RSA is designed to reduce the volatility of costs charged to customers by allowing for 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
2014	0.6	%	Decrease	$2.6 million
2013	No change			-
2012	2.1	%	Increase	$7.5 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, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual review conducted for the 12-month period ended July 31, 2013 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during the review period were reasonable and prudent. SCE&G's 2014 annual PGA hearing was held on November 6, 2014 and the SCPSC's ruling is pending.

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.  Other than unrecovered plant, 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	September 30, 2014		December 31, 2013
Regulatory Assets:
Accumulated deferred income taxes	$	250	$	256
Under collections – electric fuel adjustment clause	38		18
Environmental remediation costs	36		37
AROs and related funding	359		350
Franchise agreements	27		31
Deferred employee benefit plan costs	201		215
Planned major maintenance	7		—
Deferred losses on interest rate derivatives	318		124
Deferred pollution control costs	36		37
Unrecovered plant	139		145
DSM Programs	53		51
Other	42		39
Total Regulatory Assets	$	1,506	$	1,303

Regulatory Liabilities:
Accumulated deferred income taxes	$	17	$	19
Asset removal costs	509		495
Storm damage reserve	6		27
Deferred gains on interest rate derivatives	83		181
Planned major maintenance	—		10
Total Regulatory Liabilities	$	615	$	732

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 sites currently or formerly owned by SCE&G and are expected to be recovered over periods of up to approximately 26 years.

ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs related to generation, distribution and other properties.  These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 90 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 is recovering these amounts through cost of service rates through 2021.

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, as well as costs deferred pursuant to specific SCPSC regulatory orders. In connection with a December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are being recovered through utility rates over approximately 30 years. In connection with the October 2013 RSA order, approximately $14 million of deferred pension costs for gas operations are being recovered through utility rates over approximately 14 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 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 and accrues $18.4 million annually for fossil fueled turbine/generation equipment maintenance and collects and accrues $17.2 million annually for nuclear-related refueling charges.

Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense over periods up to approximately 50 years except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC. Also, in 2014, as discussed at Rate Matters - Electric - Cost of Fuel and Rate Matters - Electric - Base Rates, certain of these deferred amounts were applied to offset under-collected fuel balances and unrecorded net lost margin revenues related to DSM Programs.

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at certain coal-fired generating plants pursuant to specific regulatory orders.  Such costs are being recovered through utility rates through 2045. 

Unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return.

DSM Programs represent deferred costs associated with such programs.  As a result of an April 2014 SCPSC order, deferred costs are currently being recovered over approximately ten years through an approved rate rider.  See Rate Matters - Electric - Base Rates above for details regarding the 2014 filing with the SCPSC regarding recovery of these deferred costs.

Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 33 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. In 2014, $16.2 million of the reserve was applied to offset incremental storm damage costs. Also, as discussed at Rate Matters - Electric - Base Rates, in April 2014 $5.0 million of the reserve was applied to offset unrecovered net lost margin revenues related to DSM Programs.

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.

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RATE AND OTHER REGULATORY MATTERS (Tables)

9 Months Ended

Sep. 30, 2014

Regulatory Assets

Demand reduction programs [Table Text Block]

:

Year	Effective	Amount
2014	First billing cycle of May	$15.4 million
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million

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

:

Year	Action			Amount
2014	2.8	%	Increase	$66.2 million
2013	2.9	%	Increase	$67.2 million
2012	2.3	%	Increase	$52.1 million

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

:

Year	Action			Amount
2014	0.6	%	Decrease	$2.6 million
2013	No change			-
2012	2.1	%	Increase	$7.5 million

Schedule of Regulatory Assets [Table Text Block]

.

Millions of dollars	September 30, 2014		December 31, 2013
Regulatory Assets:
Accumulated deferred income taxes	$	254	$	259
Under-collections - electric fuel adjustment clause	38		18
Environmental remediation costs	40		41
AROs and related funding	378		368
Franchise agreements	27		31
Deferred employee benefit plan costs	222		238
Planned major maintenance	7		—
Deferred losses on interest rate derivatives	318		124
Deferred pollution control costs	36		37
Unrecovered plant	139		145
DSM Programs	53		51
Other	52		48
Total Regulatory Assets	$	1,564	$	1,360

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Accumulated deferred income taxes	$	22	$	24
Asset removal costs	719		695
Storm damage reserve	6		27
Monetization of bankruptcy claim	27		29
Deferred gains on interest rate derivatives	83		181
Planned major maintenance	—		10
Total Regulatory Liabilities	$	857	$	966

SCEG

Regulatory Assets

Demand reduction programs [Table Text Block]

Year	Effective	Amount
2014	First billing cycle of May	$15.4 million
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million

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

years indicated:

Year	Action			Amount
2014	2.8	%	Increase	$66.2 million
2013	2.9	%	Increase	$67.2 million
2012	2.3	%	Increase	$52.1 million

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

e years indicated:

Year	Action			Amount
2014	0.6	%	Decrease	$2.6 million
2013	No change			-
2012	2.1	%	Increase	$7.5 million

Schedule of Regulatory Assets [Table Text Block]

Millions of dollars	September 30, 2014		December 31, 2013
Regulatory Assets:
Accumulated deferred income taxes	$	250	$	256
Under collections – electric fuel adjustment clause	38		18
Environmental remediation costs	36		37
AROs and related funding	359		350
Franchise agreements	27		31
Deferred employee benefit plan costs	201		215
Planned major maintenance	7		—
Deferred losses on interest rate derivatives	318		124
Deferred pollution control costs	36		37
Unrecovered plant	139		145
DSM Programs	53		51
Other	42		39
Total Regulatory Assets	$	1,506	$	1,303

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Accumulated deferred income taxes	$	17	$	19
Asset removal costs	509		495
Storm damage reserve	6		27
Deferred gains on interest rate derivatives	83		181
Planned major maintenance	—		10
Total Regulatory Liabilities	$	615	$	732

XML

SEGMENT OF BUSINESS INFORMATION

9 Months Ended

Sep. 30, 2014

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 September 30, 2014
Electric Operations	$	739		$	1		$	275		n/a
Gas Distribution	127			—			(6		)	n/a
Retail Gas Marketing	68			—			n/a			$	(3	)
Energy Marketing	182			47			n/a			(2		)
All Other	9			103			7			(5		)
Adjustments/Eliminations	(4		)	(151		)	(7		)	154
Consolidated Total	$	1,121		$	—		$	269		$	144

Nine Months Ended September 30, 2014
Electric Operations	$	2,027		$	5		$	616	n/a
Gas Distribution	728			—			98		n/a
Retail Gas Marketing	367			—			n/a		$	16
Energy Marketing	602			154			n/a		5
All Other	27			317			21		(3		)
Adjustments/Eliminations	(15		)	(476		)	37		415
Consolidated Total	$	3,736		$	—		$	772	$	433

Three Months Ended September 30, 2013
Electric Operations	$	704		$	2		$	257		n/a
Gas Distribution	123			—			(6		)	n/a
Retail Gas Marketing	67			—			n/a			$	(2	)
Energy Marketing	152			44			n/a			1
All Other	11			95			8			(3		)
Adjustments/Eliminations	(6		)	(141		)	(4		)	135
Consolidated Total	$	1,051		$	—		$	255		$	131

Nine Months Ended September 30, 2013
Electric Operations	$	1,898		$	6		$	588	n/a
Gas Distribution	657			—			94		n/a
Retail Gas Marketing	325			—			n/a		$	16
Energy Marketing	488			133			n/a		5
All Other	30			303			22		(2		)
Adjustments/Eliminations	(20		)	(442		)	34		349
Consolidated Total	$	3,378		$	—		$	738	$	368

	September 30,		December 31,
Segment Assets	2014		2013
Electric Operations	$	9,898	$	9,488
Gas Distribution	2,365		2,340
Retail Gas Marketing	121		172
Energy Marketing	110		133
All Other	1,333		1,378
Adjustments/Eliminations	2,044		1,653
Consolidated Total	$	15,871	$	15,164

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.

	External		Operating			Earnings Available to
Millions of dollars	Revenue		Income			Common Shareholder
Three Months Ended September 30, 2014
Electric Operations	$	740	$	274		n/a
Gas Distribution	72		(2		)	n/a
Adjustments/Eliminations	—		—			$	154
Consolidated Total	$	812	$	272		$	154

Nine Months Ended September 30, 2014
Electric Operations	$	2,032	$	616	n/a
Gas Distribution	337		40		n/a
Adjustments/Eliminations	—		—		$	374
Consolidated Total	$	2,369	$	656	$	374

Three Months Ended September 30, 2013
Electric Operations	$	706	$	257		n/a
Gas Distribution	70		(2		)	n/a
Adjustments/Eliminations	—		—			$	136
Consolidated Total	$	776	$	255		$	136

Nine Months Ended September 30, 2013
Electric Operations	$	1,903	$	588	n/a
Gas Distribution	297		37		n/a
Adjustments/Eliminations	—		—		$	311
Consolidated Total	$	2,200	$	625	$	311

	September 30,		December 31,
Segment Assets	2014		2013
Electric Operations	$	9,898	$	9,488
Gas Distribution	709		686
Adjustments/Eliminations	2,792		2,526
Consolidated Total	$	13,399	$	12,700

XML

DERIVATIVE FINANCIAL INSTRUMENTS

9 Months Ended

Sep. 30, 2014

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 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 under- or over-recovery of gas costs.  These derivative financial instruments are not designated as hedges for accounting purposes.

Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI.  When the hedged transactions affect earnings, 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.  In cases in which 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.  Except as described in the following paragraph, 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. For the holding company or nonregulated subsidiaries, such amounts are recorded in AOCI.  Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income.

Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are no longer designated as cash flow hedges, and related fair value changes and settlement amounts are recorded as regulatory assets and liabilities. Upon settlement, losses on swaps will be amortized over the lives of related debt issuances, and gains may be applied to under-collected fuel, may be amortized to interest expense or may be applied as otherwise directed by the SCPSC.

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 September 30, 2014
Commodity contracts	6,000,000	10,654,000	3,193,220	19,847,220
Energy management contracts (a)	—	—	38,237,189	38,237,189
Total (a)	6,000,000	10,654,000	41,430,409	58,084,409
As of December 31, 2013
Commodity contracts	6,070,000	6,726,000	2,560,000	15,356,000
Energy management contracts (b)	—	—	27,359,958	27,359,958
Total (b)	6,070,000	6,726,000	29,919,958	42,715,958

(a)  Includes an aggregate 1,199,038 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 348,453 MMBTU related to basis swap contracts in Energy Marketing.

The Company was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $124.4 million at September 30, 2014 and $128.8 million at December 31, 2013. The Company was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.1 billion at September 30, 2014 and $1.3 billion at December 31, 2013.

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 September 30, 2014
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	4
				Other deferred credits and other liabilities	22
Commodity contracts	Derivative financial instruments	$	1	Derivative financial instruments	3
Total		$	1		$	29
Not designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	102
				Other deferred credits and other liabilities	51
Commodity contracts	Prepayments and other	$	2
Energy management contracts	Prepayments and other	5		Derivative financial instruments	4
	Other deferred debits and other assets	2		Other deferred credits and other liabilities	3
Total		$	9		$	160

As of December 31, 2013
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	5
				Other deferred credits and other liabilities	14
Commodity contracts	Prepayments and other	$	2
Total		$	2		$	19
Not designated as hedging instruments
Interest rate contracts	Prepayments and other	$	13	Derivative financial instruments	$	1
	Other deferred debits and other assets	19
Commodity contracts	Prepayments and other	2
Energy management contracts	Prepayments and other	4		Derivative financial instruments	4
	Other deferred debits and other assets	4		Other deferred credits and other liabilities	4
Total		$	42		$	9

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

Derivatives Designated as Fair Value Hedges

The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented.

Derivatives in Cash Flow Hedging Relationships

	Gain (Loss) Deferred in Regulatory Accounts						Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)						(Effective Portion)
Millions of dollars	2014			2013		Location	2014			2013
Three Months Ended September 30,
Interest rate contracts	$	(1	)	$	19	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(5	)	$	115	Interest expense	$	(2	)	$	(2	)

	Gain (Loss) Recognized in OCI, net of tax							Gain (Loss) Reclassified from AOCI into Income, net of tax
	(Effective Portion)							(Effective Portion)
Millions of dollars	2014			2013			Location	2014			2013
Three Months Ended September 30,
Interest rate contracts	—			—			Interest expense	$	(2	)	$	(2	)
Commodity contracts	$	(2	)	$	(1	)	Gas purchased for resale	—			—
Total	$	(2	)	$	(1	)		$	(2	)	$	(2	)
Nine Months Ended September 30,
Interest rate contracts	$	(4	)	$	4		Interest expense	$	(5	)	$	(5	)
Commodity contracts	1			(1		)	Gas purchased for resale	4			(2		)
Total	$	(3	)	$	3			$	(1	)	$	(7	)

As of September 30, 2014, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include an insignificant increase to gas cost and approximately $6.3 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of September 30, 2014, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2016.

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 and nine months ended September 30, 2014 and 2013, respectively.

Derivatives not designated as Hedging Instruments
Millions of dollars	Loss Deferred in Regulatory Accounts			Gain Reclassified from Deferred Accounts into Income
Three Months Ended September 30, 2014				Location	Amount
Interest rate contracts	$	(35	)	Other income	$	5
Nine Months Ended September 30, 2014
Interest rate contracts	$	(220	)	Other income	$	60

For the three and nine months ended September 30, 2013, no losses were deferred in regulatory accounts, and no amounts were reclassified from deferred accounts into income. As of September 30, 2014, the Company expects that during the next 12 months reclassifications from other current liabilities and deferred regulatory accounts to earnings arising from derivatives not designated as hedges will include $9.6 million as an increase to other income. The effect of this increase on net income will be entirely offset by net lost margin revenues from DSM Programs as further described in Note 2.

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. 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 permit the secured party to demand the posting of 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 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 may require the Company to provide collateral upon the occurrence of specific events, primarily credit downgrades.  As of September 30, 2014 and December 31, 2013, the Company has posted $69.0 million and $26.8 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 condensed consolidated balance sheets. Collateral related to noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the condensed consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of September 30, 2014 and December 31, 2013, the Company could have been required to post an additional $117.0 million and $- 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 September 30, 2014 and December 31, 2013 is $187.0 million and $25.2 million, respectively.

In addition, as of September 30, 2014 and December 31, 2013, 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 September 30, 2014 and December 31, 2013, the Company could request $- million and $34.1 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 September 30, 2014 and December 31, 2013 is $- million and $34.1 million, respectively. In addition, at September 30, 2014, the Company could have called on letters of credit in the amount of $5.0 million related to $6.0 million in commodity derivatives that are in a net asset position, compared to letters of credit of $6.0 million related to derivatives of $6.0 million at December 31, 2013, 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 September 30, 2014
Interest rate contracts	—		—			—		—	—	—
Commodity contracts	$	3	$	(1	)	$	2	—	—	$	2
Energy management contracts	7		(1		)	6		—	—	6
Total	$	10	$	(2	)	$	8	—	—	$	8
Balance sheet location	Prepayments and other					$	6
	Other deferred debits and other assets					2
	Total					$	8

As of December 31, 2013
Interest rate contracts	$	32	—	$	32	$	(1	)	—	$	31
Commodity contracts	4		—	4		—			—	4
Energy management contracts	8		—	8		—			—	8
Total	$	21	—	$	44	$	(1	)	—	$	43
Balance sheet location	Prepayments and other			$	21
	Other deferred debits and other assets			23
	Total			$	44

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 September 30, 2014
Interest rate contracts	$	179	—			$	179	—	$	(63	)	$	116
Commodity contracts	3		$	(1	)	2		—	(1		)	1
Energy management contracts	7		(1		)	6		—	(5		)	1
Total	$	189	$	(2	)	$	187	—	$	(69	)	$	118
Balance sheet location	Derivative financial instruments					$	112
	Other deferred credits and other liabilities					75
	Total					$	187

As of December 31, 2013
Interest rate contracts	$	20	—	$	20	$	(1	)	$	(19	)	—
Energy management contracts	8		—	8		—			(6		)	$	2
Total	$	28	—	$	28	$	(1	)	$	(25	)	$	2
Balance sheet location	Derivative financial instruments			$	10
	Other deferred credits and other liabilities			18
	Total			$	28

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. Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are no longer designated as cash flow hedges, and fair value changes and settlement amounts are recorded as regulatory assets and liabilities. Upon settlement, losses on swaps will be amortized over the lives of related debt issuances, and gains may be applied to under-collected fuel, may be amortized to interest expense or may be applied as otherwise directed by the SCPSC.

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 $36.4 million at September 30, 2014 and $36.4 million at December 31, 2013. Consolidated SCE&G was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.1 billion at September 30, 2014 and $1.3 billion at December 31, 2013, respectively.

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 September 30, 2014
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	2
				Other deferred credits and other liabilities	4
Total					$	6
Not designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	102
				Other deferred credits and other liabilities	51
Total					$	153
As of December 31, 2013
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	1
Total					$	1
Not designated as hedging instruments
Interest rate contracts	Prepayments and other	$	13	Derivative financial instruments	$	1
	Other deferred debits and other assets	19
Total		$	32		$	1

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

Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Deferred in Regulatory Accounts						Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)						(Effective Portion)
Millions of dollars	2014			2013		Location	2014			2013
Three Months Ended September 30,
Interest rate contracts	$	(1	)	$	19	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(5	)	$	115	Interest expense	$	(2	)	$	(2	)

Hedge Ineffectiveness

Other gains (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three and nine months ended September 30, 2014 and 2013, respectively.

Derivatives not designated as Hedging Instruments
Millions of dollars	Loss Deferred in Regulatory Accounts			Gain Reclassified from Deferred Accounts into Income
				Location	Amount
Three Months Ended September 30, 2014
Interest rate contracts	$	(35	)	Other income	$	5
Nine Months Ended September 30, 2014
Interest rate contracts	$	(220	)	Other income	$	60

For the three and nine months ended September 30, 2013, no losses were deferred in regulatory accounts, and no amounts were reclassified from deferred accounts into income. As of September 30, 2014, Consolidated SCE&G expects that during the next 12 months reclassifications from other current liabilities and deferred regulatory accounts to earnings arising from derivatives not designated as hedges will include $9.6 million as an increase to other income. The effect of this increase on net income will be entirely offset by net lost margin revenues from DSM Programs as further described in Note 2.

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. 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 permit the secured party to demand the posting of 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 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 may require Consolidated SCE&G to provide collateral upon the occurrence of specific events, primarily credit downgrades.  As of September 30, 2014 and December 31, 2013, Consolidated SCE&G has posted $40.1 million and $1.5 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 condensed consolidated balance sheets. Collateral related to noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the condensed consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of September 30, 2014 and December 31, 2013, Consolidated SCE&G could have been required to post an additional $118.6 million and $- , 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 September 30, 2014 and December 31, 2013 is $158.6 million and $1.0 million, respectively.

In addition, as of September 30, 2014 and December 31, 2013, 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 September 30, 2014 and December 31, 2013, Consolidated SCE&G could request $- and $31.7 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 September 30, 2014 and December 31, 2013 is $- and $31.7 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 September 30, 2014
Interest rate contracts	—	—	—	—	—	—

As of December 31, 2013
Interest rate contracts	$	32	—	$	32	$	(1	)	—	$	31
Balance Sheet Location	Prepayments and other			$	13
	Other deferred debits and other assets			19
	Total			$	32

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 September 30, 2014
Interest rate contracts	$	159	—	$	159	—	$	(40	)	$	119
Balance Sheet Location	Derivative financial instruments			$	104
	Other deferred credits and other liabilities			55
	Total			$	159

As of December 31, 2013
Interest rate contracts	$	2	—	$	2	$	(1	)	$	(1	)	—
Balance Sheet Location	Derivative financial instruments			$	2

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LONG-TERM AND SHORT-TERM DEBT

9 Months Ended

Sep. 30, 2014

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In May 2014, SCE&G issued $300 million of 4.5% first mortgage bonds due June 1, 2064. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

In March 2013, SCE&G entered into a contract for the purchase of nuclear fuel totaling $100 million and payable in 2016.

In January 2013, JEDA issued at a premium, for the benefit of SCE&G, $39.5 million of 4.00% 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.

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	September 30, 2014			December 31, 2013			September 30, 2014			December 31, 2013			September 30, 2014		December 31, 2013
Lines of credit:
Total committed long-term	$	300		$	300		$	1,400		$	1,400		$	100	$	100
Outstanding commercial paper (270 or fewer days)	$	127		$	125		$	361		$	251		—		—
Weighted average interest rate	0.35		%	0.39		%	0.28		%	0.27		%	—		—
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—		—
Available	$	170		$	172		$	1,039		$	1,149		$	100	$	100

SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million, $1.2 billion (of which $500 million relates to Fuel Company) and $100 million, respectively. In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million. In October 2014, the term of the five-year agreements was extended by one year, such that they expire in October 2019. The three-year agreement expires in October 2016. 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 Company expects to replace the letters of credit 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 May 2014, SCE&G issued $300 million of 4.5% first mortgage bonds due June 1, 2064. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

In March 2013, SCE&G entered into a contract for the purchase of nuclear fuel totaling $100 million and payable in 2016.

In January 2013, JEDA issued at a premium, for the benefit of SCE&G, $39.5 million of 4.00% 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.

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	September 30, 2014			December 31, 2013
Lines of credit:
Total committed long-term	$	1,400		$	1,400
Outstanding commercial paper (270 or fewer days)	$	361		$	251
Weighted average interest rate	0.28		%	0.27		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	1,039		$	1,149

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). In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million. In October 2014, the term of the five-year agreements was extended by one year, such that they expire in October 2019. The three-year agreement expires in October 2016. 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. Consolidated SCE&G expects to replace the letters of credit 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 were not significant for any period presented. At September 30, 2014 and December 31, 2013, Consolidated SCE&G had outstanding money pool borrowings from an affiliate of $20.8 million and $27.3 million, respectively.

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INCOME TAXES

9 Months Ended

Sep. 30, 2014

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

During 2013 the Company amended certain of its tax returns to claim certain tax-defined research and development deductions and credits. In connection with these filings, the Company recorded an unrecognized tax benefit of $3.0 million. During 2014 the Company filed its 2013 tax return and amended additional tax returns to claim certain tax-defined research and development deductions and credits. In connection with these filings, the Company increased its unrecognized tax benefit by $8.2 million (for a total of $11.2 million). If recognized, this tax benefit would affect the Company’s effective tax rate. No other material changes in the status of the Company’s tax positions have occurred through September 30, 2014. These amended returns are now under examination by the IRS.

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  Because no refunds related to the unrecognized tax benefits have yet been received, the Company has not recorded any interest expense or penalties associated with them.

During the third quarter of 2013, the State of North Carolina passed legislation that lowered the state corporate income tax rate from 6.9% to 6.0% in 2014 and 5.0% in 2015.  In connection with this change in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The change in income tax rates did not and is not expected to have a material impact on the Company’s financial position, results of operations or cash flows. 

Additionally, during the third quarter of 2013, the IRS issued final regulations regarding the capitalization of certain costs for income tax purposes and re-proposed certain other related regulations (collectively referred to as tangible personal property regulations).  Related IRS revenue procedures were then issued on January 24, 2014. These regulations and procedures did not and are not expected to have a material impact on the Company's financial position, results of operations or cash flows.

SCEG

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

During 2013 SCANA amended certain of its consolidated tax returns to claim certain tax-defined research and development deductions and credits. In connection with these filings, Consolidated SCE&G recorded an unrecognized tax benefit of $3.0 million. During 2014 SCANA filed its 2013 tax return and amended additional tax returns to claim certain tax-defined research and development deductions and credits. In connection with these filings, Consolidated SCE&G increased its unrecognized tax benefit by $8.2 million (for a total of $11.2 million). If recognized, this tax benefit would affect Consolidated SCE&G's effective tax rate. No other material changes in the status of Consolidated SCE&G’s tax positions have occurred through September 30, 2014. These amended returns are now under examination by the IRS.

                Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  Because no refunds related to the unrecognized tax benefits have yet been received, Consolidated SCE&G has not recorded any interest expense or penalties associated with them.

Additionally, during the third quarter of 2013, the IRS issued final regulations regarding the capitalization of certain costs for income tax purposes and re-proposed certain other related regulations (collectively referred to as tangible personal property regulations).  Related IRS revenue procedures were then issued on January 24, 2014. These regulations and procedures did not and are not expected to have a material impact on Consolidated SCE&G's financial position, results of operations or cash flows.

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

9 Months Ended

Sep. 30, 2014

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 data.  Fair value measurements, and the level within the fair value hierarchyin which the measurements fall, were as follows:

	As of September 30, 2014				As of December 31, 2013
Millions of dollars	Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	$	12	—		$	9	—
Interest rate contracts	—		—		—		$	32
Commodity contracts	2		$	1	2		2
Energy management contracts	1		6		1		7
Liabilities:
Interest rate contracts	—		179		—		20
Commodity contracts	—		3		—		—
Energy management contracts	—		10		—		12

There were no Level 3 fair value measurements for either period presented, and 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 September 30, 2014 and December 31, 2013 were as follows:

	September 30, 2014				December 31, 2013
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	5,733.2	$	6,469.6	$	5,449.3	$	5,916.3

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. 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 Level 2 measurements were as follows: 

Millions of dollars		September 30, 2014		December 31, 2013
Assets -	Interest rate contracts	—		$	32
Liabilities -	Interest rate contracts	$	159	2

There were no Level 1 or Level 3 fair value measurements for either period presented, and 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 September 30, 2014 and December 31, 2013 were as follows:

	September 30, 2014				December 31, 2013
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,344.3	$	4,950.6	$	4,054.9	$	4,433.0

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.  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.

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COMMON EQUITY (Details) (USD $)	3 Months Ended			9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Mar. 31, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	200,000,000			200,000,000		200,000,000
COMMON EQUITY [Abstract]
Forward Contract Indexed to Issuer's Equity, Indexed Shares			6,600,000
Dividends declared				$ (223,000,000)	$ (212,000,000)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax				(2,000,000)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax				1,000,000	1,000,000
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	145,000,000	137,000,000		432,000,000	383,000,000
Stock Issued During Period, Value, New Issues				75,000,000	273,000,000
Common Stock, Shares, Outstanding	142,200,000			142,200,000		140,700,000
Proceeds from exercise of equity forward sales agreements			196,200,000
Common Stock, Value, Outstanding	2,355,000,000	2,256,000,000		2,355,000,000	2,256,000,000	2,280,000,000	1,983,000,000
Accumulated Other Comprehensive Income (Loss), Net of Tax	(61,000,000)	(71,000,000)		(61,000,000)	(71,000,000)	(60,000,000)	(86,000,000)
Retained Earnings, Unappropriated	2,654,000,000	2,413,000,000		2,654,000,000	2,413,000,000	2,444,000,000	2,257,000,000
Other Comprehensive Income (Loss), Net of Tax	1,000,000	6,000,000		(1,000,000)	15,000,000
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(2,000,000)	(1,000,000)		(3,000,000)	3,000,000
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant		insignificant	insignificant
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax		4,000,000			4,000,000
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	2,000,000	2,000,000		1,000,000	7,000,000
Income Available to Common Shareholders	144,000,000	131,000,000		433,000,000	368,000,000
Common equity	4,948,000,000	4,598,000,000		4,948,000,000	4,598,000,000	4,664,000,000	4,154,000,000
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(54,000,000)	(60,000,000)		(54,000,000)	(60,000,000)	(52,000,000)	(70,000,000)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(7,000,000)	(11,000,000)		(7,000,000)	(11,000,000)	(8,000,000)	(16,000,000)
SCEG
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	50,000,000			50,000,000
COMMON EQUITY [Abstract]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	157,000,000	139,000,000		383,000,000	319,000,000
Proceeds from Contributions from Parent				82,000,000	285,000,000
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax				0	1,000,000
Net Income (Loss) Attributable to Noncontrolling Interest	3,000,000	3,000,000		9,000,000	8,000,000
Dividends				(197,000,000)	195,000,000
Comprehensive Income (Loss), Net of Tax, Attributable to Parent				383,000,000	320,000,000
Common Stock, Shares, Outstanding	40,300,000			40,300,000		40,300,000
Preferred Stock, Shares Authorized	20,000,000			20,000,000
Preferred Stock, Shares Outstanding	1,000			1,000
Common Stock, Value, Outstanding	2,561,000,000			2,561,000,000		2,479,000,000
Preferred Stock, Value, Issued	100,000			100,000
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3,000,000)			(3,000,000)		(3,000,000)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	4,757,000,000	4,453,000,000		4,757,000,000	4,453,000,000	4,489,000,000	4,043,000,000
Retained Earnings, Unappropriated	2,078,000,000			2,078,000,000		1,896,000,000
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant		insignificant	insignificant
Reclassifcations of deferred employee benefit costs				not significant
Common equity	4,636,000,000			4,636,000,000		4,372,000,000
SCEG excluding VIEs [Member]
COMMON EQUITY [Abstract]
Proceeds from Contributions from Parent				82,000,000	285,000,000
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax				0	1,000,000
Dividends				(192,000,000)	190,000,000
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	154,000,000	137,000,000		374,000,000	312,000,000
Common Stock, Value, Outstanding	2,561,000,000	2,452,000,000		2,561,000,000	2,452,000,000	2,479,000,000	2,167,000,000
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3,000,000)	(3,000,000)		(3,000,000)	(3,000,000)	(3,000,000)	(4,000,000)
Retained Earnings, Unappropriated	2,078,000,000	1,887,000,000		2,078,000,000	1,887,000,000	1,896,000,000	1,766,000,000
Income Available to Common Shareholders				374,000,000	311,000,000
Noncontrolling Interest [Member]
COMMON EQUITY [Abstract]
Net Income (Loss) Attributable to Noncontrolling Interest				9,000,000	8,000,000
Dividends				5,000,000	5,000,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	121,000,000	117,000,000		121,000,000	117,000,000	117,000,000	114,000,000
Interest Rate Contract
COMMON EQUITY [Abstract]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	0	0		(4,000,000)	4,000,000
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	(2,000,000)	(2,000,000)		(5,000,000)	(5,000,000)
Commodity Contract
COMMON EQUITY [Abstract]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(2,000,000)	(1,000,000)		1,000,000	(1,000,000)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ 0	$ 0		$ 4,000,000	$ (2,000,000)

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2014

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 47% and 48% of PSNC Energy’s natural gas inventory at September 30, 2014

and December 31, 2013, respectively, with a carrying value of $25.4 million and $22.8 million, respectively, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management feesof which 75% are credited to rate payers. No fees are received under supply service agreements. The agreements expire 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.

Plant to be retired [Policy Text Block]

Plant to be Retired

In 2012 SCE&G identified six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. Three of these units had been retired by December 31, 2013, and their net carrying value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units is identified as Plant to be Retired, Net in the condensed 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 use and in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC.

SCEG

Significant Accounting Policies

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

Variable Interest Entities

SCE&G has determined that it is the primary beneficiary of 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 $502 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.

Plant to be retired [Policy Text Block]

Plant to be Retired

In 2012 SCE&G identified six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. Three of these units had been retired by December 31, 2013, and their net carrying value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units is identified as Plant to be Retired, Net in the condensed 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 use and in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC.

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DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

9 Months Ended

Sep. 30, 2014

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 September 30, 2014
Commodity contracts	6,000,000	10,654,000	3,193,220	19,847,220
Energy management contracts (a)	—	—	38,237,189	38,237,189
Total (a)	6,000,000	10,654,000	41,430,409	58,084,409
As of December 31, 2013
Commodity contracts	6,070,000	6,726,000	2,560,000	15,356,000
Energy management contracts (b)	—	—	27,359,958	27,359,958
Total (b)	6,070,000	6,726,000	29,919,958	42,715,958

(a)  Includes an aggregate 1,199,038 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 348,453 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 September 30, 2014
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	4
				Other deferred credits and other liabilities	22
Commodity contracts	Derivative financial instruments	$	1	Derivative financial instruments	3
Total		$	1		$	29
Not designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	102
				Other deferred credits and other liabilities	51
Commodity contracts	Prepayments and other	$	2
Energy management contracts	Prepayments and other	5		Derivative financial instruments	4
	Other deferred debits and other assets	2		Other deferred credits and other liabilities	3
Total		$	9		$	160

As of December 31, 2013
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	5
				Other deferred credits and other liabilities	14
Commodity contracts	Prepayments and other	$	2
Total		$	2		$	19
Not designated as hedging instruments
Interest rate contracts	Prepayments and other	$	13	Derivative financial instruments	$	1
	Other deferred debits and other assets	19
Commodity contracts	Prepayments and other	2
Energy management contracts	Prepayments and other	4		Derivative financial instruments	4
	Other deferred debits and other assets	4		Other deferred credits and other liabilities	4
Total		$	42		$	9

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

Derivatives in Cash Flow Hedging Relationships

	Gain (Loss) Deferred in Regulatory Accounts						Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)						(Effective Portion)
Millions of dollars	2014			2013		Location	2014			2013
Three Months Ended September 30,
Interest rate contracts	$	(1	)	$	19	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(5	)	$	115	Interest expense	$	(2	)	$	(2	)

	Gain (Loss) Recognized in OCI, net of tax							Gain (Loss) Reclassified from AOCI into Income, net of tax
	(Effective Portion)							(Effective Portion)
Millions of dollars	2014			2013			Location	2014			2013
Three Months Ended September 30,
Interest rate contracts	—			—			Interest expense	$	(2	)	$	(2	)
Commodity contracts	$	(2	)	$	(1	)	Gas purchased for resale	—			—
Total	$	(2	)	$	(1	)		$	(2	)	$	(2	)
Nine Months Ended September 30,
Interest rate contracts	$	(4	)	$	4		Interest expense	$	(5	)	$	(5	)
Commodity contracts	1			(1		)	Gas purchased for resale	4			(2		)
Total	$	(3	)	$	3			$	(1	)	$	(7	)

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
Millions of dollars	Loss Deferred in Regulatory Accounts			Gain Reclassified from Deferred Accounts into Income
Three Months Ended September 30, 2014				Location	Amount
Interest rate contracts	$	(35	)	Other income	$	5
Nine Months Ended September 30, 2014
Interest rate contracts	$	(220	)	Other income	$	60

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 September 30, 2014
Interest rate contracts	—		—			—		—	—	—
Commodity contracts	$	3	$	(1	)	$	2	—	—	$	2
Energy management contracts	7		(1		)	6		—	—	6
Total	$	10	$	(2	)	$	8	—	—	$	8
Balance sheet location	Prepayments and other					$	6
	Other deferred debits and other assets					2
	Total					$	8

As of December 31, 2013
Interest rate contracts	$	32	—	$	32	$	(1	)	—	$	31
Commodity contracts	4		—	4		—			—	4
Energy management contracts	8		—	8		—			—	8
Total	$	21	—	$	44	$	(1	)	—	$	43
Balance sheet location	Prepayments and other			$	21
	Other deferred debits and other assets			23
	Total			$	44

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 September 30, 2014
Interest rate contracts	$	179	—			$	179	—	$	(63	)	$	116
Commodity contracts	3		$	(1	)	2		—	(1		)	1
Energy management contracts	7		(1		)	6		—	(5		)	1
Total	$	189	$	(2	)	$	187	—	$	(69	)	$	118
Balance sheet location	Derivative financial instruments					$	112
	Other deferred credits and other liabilities					75
	Total					$	187

As of December 31, 2013
Interest rate contracts	$	20	—	$	20	$	(1	)	$	(19	)	—
Energy management contracts	8		—	8		—			(6		)	$	2
Total	$	28	—	$	28	$	(1	)	$	(25	)	$	2
Balance sheet location	Derivative financial instruments			$	10
	Other deferred credits and other liabilities			18
	Total			$	28

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 September 30, 2014
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	2
				Other deferred credits and other liabilities	4
Total					$	6
Not designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	102
				Other deferred credits and other liabilities	51
Total					$	153
As of December 31, 2013
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	1
Total					$	1
Not designated as hedging instruments
Interest rate contracts	Prepayments and other	$	13	Derivative financial instruments	$	1
	Other deferred debits and other assets	19
Total		$	32		$	1

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

Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Deferred in Regulatory Accounts						Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)						(Effective Portion)
Millions of dollars	2014			2013		Location	2014			2013
Three Months Ended September 30,
Interest rate contracts	$	(1	)	$	19	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(5	)	$	115	Interest expense	$	(2	)	$	(2	)

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
Millions of dollars	Loss Deferred in Regulatory Accounts			Gain Reclassified from Deferred Accounts into Income
				Location	Amount
Three Months Ended September 30, 2014
Interest rate contracts	$	(35	)	Other income	$	5
Nine Months Ended September 30, 2014
Interest rate contracts	$	(220	)	Other income	$	60

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 September 30, 2014
Interest rate contracts	—	—	—	—	—	—

As of December 31, 2013
Interest rate contracts	$	32	—	$	32	$	(1	)	—	$	31
Balance Sheet Location	Prepayments and other			$	13
	Other deferred debits and other assets			19
	Total			$	32

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 September 30, 2014
Interest rate contracts	$	159	—	$	159	—	$	(40	)	$	119
Balance Sheet Location	Derivative financial instruments			$	104
	Other deferred credits and other liabilities			55
	Total			$	159

As of December 31, 2013
Interest rate contracts	$	2	—	$	2	$	(1	)	$	(1	)	—
Balance Sheet Location	Derivative financial instruments			$	2

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Additional Collateral, Aggregate Fair Value	$ 117,000,000	$ 0
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	8,000,000	44,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	187,000,000	28,000,000
Interest Rate Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	32,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	179,000,000	20,000,000
Commodity Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	2,000,000	4,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	2,000,000
Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets, Fair Value Disclosure [Abstract]
Available-for-sale Securities	12,000,000	9,000,000
Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest Rate Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	2,000,000	2,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other energy management contracts
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	1,000,000	1,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0	0
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 Asset	0	32,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	179,000,000	20,000,000
Fair Value, Inputs, Level 2 [Member] | Commodity Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	1,000,000	2,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	3,000,000	0
Fair Value, Inputs, Level 2 [Member] | Other energy management contracts
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	6,000,000	7,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	10,000,000	12,000,000
SCEG
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Additional Collateral, Aggregate Fair Value	118,600,000	0
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		32,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	159,000,000
SCEG | Interest Rate Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	32,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	159,000,000	2,000,000
SCEG | Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	32,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	$ 159,000,000	$ 2,000,000

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Allowance for Funds Used During Construction, Capitalized Interest	$ 5	$ 4	$ 13	$ 10
SCEG
Allowance for Funds Used During Construction, Capitalized Interest	$ 5	$ 4	$ 11	$ 9

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2014

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

In 2012 SCE&G identified six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. Three of these units had been retired by December 31, 2013, and their net carrying value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units is identified as Plant to be Retired, Net in the condensed 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 use and in rate base, and SCE&G depreciates 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:     

	Third Quarter		Year to Date
Millions	2014	2013	2014	2013
Weighted Average Shares Outstanding - Basic	142.1	140.1	141.6	138.0
Effect of dilutive equity forward shares	—	—	—	0.6
Weighted Average Shares - Diluted	142.1	140.1	141.6	138.6

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 47% and 48% of PSNC Energy’s natural gas inventory at September 30, 2014

and December 31, 2013, respectively, with a carrying value of $25.4 million and $22.8 million, respectively, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management feesof which 75% are credited to rate payers. No fees are received under supply service agreements. The agreements expire March 31, 2015. 

New Accounting Matter

In May 2014, the Financial Accounting Standards Board issued new accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The Company will be required to adopt the new guidance in the first quarter of 2017, and early adoption is not permitted.  The Company has not determined the impact this guidance will have on its results of operations, cash flows or financial position.

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 Entities

SCE&G has determined that it is the primary beneficiary of 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 $502 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

In 2012 SCE&G identified six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. Three of these units had been retired by December 31, 2013, and their net carrying value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units is identified as Plant to be Retired, Net in the condensed 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 use and in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC.

New Accounting Matter

In May 2014, the Financial Accounting Standards Board issued new accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. Consolidated SCE&G will be required to adopt the new guidance in the first quarter of 2017, and early adoption is not permitted.  Consolidated SCE&G has not determined the impact this guidance will have on its results of operations, cash flows or financial position.

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)

9 Months Ended

Sep. 30, 2014

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

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

Fair value measurements, and the level within the fair value hierarchyin which the measurements fall, were as follows:

	As of September 30, 2014				As of December 31, 2013
Millions of dollars	Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	$	12	—		$	9	—
Interest rate contracts	—		—		—		$	32
Commodity contracts	2		$	1	2		2
Energy management contracts	1		6		1		7
Liabilities:
Interest rate contracts	—		179		—		20
Commodity contracts	—		3		—		—
Energy management contracts	—		10		—		12

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

Financial instruments for which the carrying amount may not equal estimated fair value at September 30, 2014 and December 31, 2013 were as follows:

	September 30, 2014				December 31, 2013
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	5,733.2	$	6,469.6	$	5,449.3	$	5,916.3

SCEG

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

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

Fair value Level 2 measurements were as follows: 

Millions of dollars		September 30, 2014		December 31, 2013
Assets -	Interest rate contracts	—		$	32
Liabilities -	Interest rate contracts	$	159	2

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

Financial instruments for which the carrying amount may not equal estimated fair value at September 30, 2014 and December 31, 2013 were as follows:

	September 30, 2014				December 31, 2013
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,344.3	$	4,950.6	$	4,054.9	$	4,433.0

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details) (USD $)	Sep. 30, 2014 MMBTU		Dec. 31, 2013 MMBTU
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	58,084,409	[1]	42,715,958	[2]
Nonmonetary Notional Amount of Basis Swap, Price Risk Derivative Instruments Not Designated as Hedging Instruments	1,199,038		348,453
Interest Rate Derivatives [Abstract]
Derivative, Notional Amount	$ 124,400,000		$ 128,800,000
Interest Rate Derivative Instruments Not Designated as Hedging Instruments, Liability at Fair Value	1,100,000,000		1,300,000,000
Additional Collateral, Aggregate Fair Value	117,000,000		0
Derivative, Net Liability Position, Aggregate Fair Value	187,000,000		25,200,000
Cash collateral to request from interest rate derivative counterparty	0		34,100,000
Interest Rate Derivative, net asset position	0		34,100,000
Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6,000,000		6,070,000
Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	10,654,000		6,726,000
Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	41,430,409	[1]	29,919,958	[2]
Commodity Contract
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	19,847,220		15,356,000
Commodity Contract | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6,000,000		6,070,000
Commodity Contract | Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	10,654,000		6,726,000
Commodity Contract | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	3,193,220		2,560,000
Energy Management Contracts [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	38,237,189		27,359,958
Energy Management Contracts [Member] | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0		0
Energy Management Contracts [Member] | Retail Gas Marketing
Derivative [Line Items]
Derivative not designated as hedging, nonmonetary amount	0		0
Energy Management Contracts [Member] | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	38,237,189		27,359,958
SCEG
Interest Rate Derivatives [Abstract]
Derivative, Notional Amount	36,400,000		36,400,000
Interest Rate Derivative Instruments Not Designated as Hedging Instruments, Liability at Fair Value	1,100,000,000		1,300,000,000
Additional Collateral, Aggregate Fair Value	118,600,000		0
Derivative, Net Liability Position, Aggregate Fair Value	158,600,000		1,000,000
Cash collateral to request from interest rate derivative counterparty	0		31,700,000
Interest Rate Derivative, net asset position	$ 0		$ 31,700,000

[1] (a) Includes an aggregate 1,199,038 MMBTU related to basis swap contracts in Energy Marketing.

[2] (b) Includes an aggregate 348,453 MMBTU related to basis swap contracts in Energy Marketing.

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AFFILIATED TRANSACTIONS - SCEG (SCEG)

9 Months Ended

Sep. 30, 2014

SCEG

AFFILIATED TRANSACTIONS

AFFILIATED TRANSACTIONS

CGT transports natural gas to SCE&G to serve retail gas customers and certain electric generation requirements.  Such purchases totaled approximately $6.9 million and $8.4 million for the three months ended September 30, 2014 and 2013, respectively, and $21.6 million and $25.3 million for the nine months ended September 30, 2014 and 2013, respectively.  SCE&G's payables to CGT for transportation services were $3.1 million at September 30, 2014 and $3.3 million at December 31, 2013. SCE&G's receivables from CGT for transportation services were $- million at September 30, 2014 and $1.3 million at December 31, 2013.

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 $46.8 million and $43.4 million for the three months ended September 30, 2014 and 2013, respectively, and $154.1 million and $132.7 million for the nine months ended September 30, 2014 and 2013, respectively.  SCE&G’s payables to SEMI for such purposes were $14.5 million at September 30, 2014 and $12.5 million at December 31, 2013.

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 accounts for this investment using the equity method.  SCE&G’s total purchases from this affiliate were $82.4 million and $41.9 million for the three months ended September 30, 2014 and 2013, respectively, and $191.9 million and $73.7 million for the nine months ended September 30, 2014 and 2013, respectively.  SCE&G’s total sales to this affiliate were $82.0 million and $41.8 million for the three months ended September 30, 2014 and 2013, respectively, and $190.9 million and $73.4 million for the nine months ended September 30, 2014 and 2013, respectively. SCE&G’s receivable from this affiliate was $26.9 million at September 30, 2014 and $18.0 million at December 31, 2013.  SCE&G’s payable to this affiliate was $27.0 million at September 30, 2014 and $18.0 million at December 31, 2013.

SCANA Services provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems services, telecommunications 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. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services were $65.0 million and $63.5 million for the three months ended September 30, 2014 and 2013, respectively, and $211.4 million and $209.2 million for the nine months ended September 30, 2014 and 2013, respectively. Consolidated SCE&G's payables to SCANA Services for these services were $47.0 million at September 30, 2014 and $49.1 million at December 31, 2013.

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