10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2015

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

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

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

	Description of	Shares Outstanding
Registrant	Common Stock	at April 30, 2015
SCANA Corporation	Without Par Value	142,916,917
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 

MARCH 31, 2015

			Page
Cautionary Statement Regarding Forward-Looking Information			3
Definitions			4
PART I. FINANCIAL INFORMATION
SCANA Corporation Financial Section			6
	Item 1.	Financial Statements	6
		Condensed Consolidated Balance Sheets	6
		Condensed Consolidated Statements of Income	8
		Condensed Consolidated Statements of Comprehensive Income	9
		Condensed Consolidated Statements of Cash Flows	10
		Notes to Condensed Consolidated Financial Statements	11
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36
	Item 4.	Controls and Procedures	37
South Carolina Electric & Gas Company Financial Section			38
	Item 1.	Financial Statements	38
		Condensed Consolidated Balance Sheets	38
		Condensed Consolidated Statements of Income	40
		Condensed Consolidated Statements of Comprehensive Income	41
		Condensed Consolidated Statements of Cash Flows	42
		Notes to Condensed Consolidated Financial Statements	43
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	58
	Item 4.	Controls and Procedures	61
PART II. OTHER INFORMATION			61
	Item 5.	Other Information	61
	Item 6.	Exhibits	62
Signatures			63
Exhibit Index			64

2

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

(2) legislative and 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, including nuclear generating facilities, and the results of efforts to operate its electric and gas systems and assets in accordance with acceptable performance standards;

(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 quality and 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 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
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
DER	Distributed Energy Resource
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
FASB	Financial Accounting Standards Board
FERC	United States Federal Energy Regulatory Commission
Fuel Company	South Carolina Fuel Company, Inc.
GENCO	South Carolina Generating Company, Inc.
GHG	Greenhouse Gas
GPSC	Georgia Public Service Commission
GWh	Gigawatt hour
IRP	Integrated Resource Plan
IRS	Internal Revenue Service
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
MATS	Mercury and Air Toxics Standards

4

MGP	Manufactured Gas Plant
MMBTU	Million British Thermal Units
MW	Megawatt
NAAQS	National Ambient Air Quality Standards
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
SCI	SCANA Communications, Inc.
SCPSC	Public Service Commission of South Carolina
SEC	United States Securities and Exchange Commission
SEMI	SCANA Energy Marketing, Inc.
Spirit Communications	SCTG Communications, Inc. (a wholly owned subsidiary of SCTG, LLC) d/b/a Spirit Communications
Summer Station	V. C. Summer Nuclear Station
VIE	Variable Interest Entity

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PART I.  FINANCIAL INFORMATION

SCANA CORPORATION FINANCIAL SECTION

ITEM 1. F INANCIAL STATEMENTS

SCANA CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited) 

Millions of dollars	March 31, 2015			December 31, 2014
Assets
Utility Plant In Service	$	12,382		$	12,289
Accumulated Depreciation and Amortization	(4,141		)	(4,088		)
Construction Work in Progress	3,478			3,323
Plant to be Retired, Net	164			169
Nuclear Fuel, Net of Accumulated Amortization	317			329
Goodwill, net of writedown of $230	210			210
Utility Plant, Net	12,410			12,232
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $120 and $122	285			284
Assets held in trust, net-nuclear decommissioning	115			113
Other investments	77			75
Nonutility Property and Investments, Net	477			472
Current Assets:
Cash and cash equivalents	31			137
Receivables, net of allowance for uncollectible accounts of $7 and $7	778			838
Inventories (at average cost):
Fuel and gas supply	175			222
Materials and supplies	143			139
Prepayments	104			320
Other current assets	204			148
Assets held for sale	—			341
Total Current Assets	1,435			2,145
Deferred Debits and Other Assets:
Regulatory assets	1,890			1,823
Other	194			180
Total Deferred Debits and Other Assets	2,084			2,003
Total	$	16,406		$	16,852

See Notes to Condensed Consolidated Financial Statements.

6

Millions of dollars	March 31, 2015			December 31, 2014
Capitalization and Liabilities
Common Stock - no par value (shares outstanding: March 31, 2015- 142.9 million; December 31, 2014 - 142.7 million)	$	2,392		$	2,378
Retained Earnings	3,006			2,684
Accumulated Other Comprehensive Loss	(73		)	(75		)
Total Common Equity	5,325			4,987
Long-Term Debt, net	5,525			5,531
Total Capitalization	10,850			10,518
Current Liabilities:
Short-term borrowings	625			918
Current portion of long-term debt	16			166
Accounts payable	331			520
Customer deposits and customer prepayments	109			98
Taxes accrued	110			182
Interest accrued	76			83
Dividends declared	76			73
Liabilities held for sale	—			52
Derivative financial instruments	292			233
Other	97			208
Total Current Liabilities	1,732			2,533
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,863			1,866
Deferred investment tax credits	27			28
Asset retirement obligations	566			563
Postretirement benefits	316			315
Regulatory liabilities	829			814
Other	223			215
Total Deferred Credits and Other Liabilities	3,824			3,801
Commitments and Contingencies (Note 9)	—			—
Total	$	16,406		$	16,852

See Notes to Condensed Consolidated Financial Statements.

7

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended
	March 31,
Millions of dollars, except per share amounts	2015			2014
Operating Revenues:
Electric	$	629		$	678
Gas - regulated	369			458
Gas - nonregulated	391			454
Total Operating Revenues	1,389			1,590
Operating Expenses:
Fuel used in electric generation	174			212
Purchased power	13			25
Gas purchased for resale	523			670
Other operation and maintenance	173			180
Depreciation and amortization	96			95
Other taxes	59			58
Total Operating Expenses	1,038			1,240
Gain on sale of CGT, net of transaction costs	235			—
Operating Income	586			350
Other Income (Expense):
Other income	19			15
Other expense	(12		)	(14		)
Gain on sale of SCI, net of transaction costs	107			—
Interest charges, net of allowance for borrowed funds used during construction of $3 and $3	(77		)	(76		)
Allowance for equity funds used during construction	5			7
Total Other Income (Expense)	42			(68		)
Income Before Income Tax Expense	628			282
Income Tax Expense	228			89
Net Income	$	400		$	193
Earnings Per Share of Common Stock	$	2.80		$	1.37
Weighted Average Common Shares Outstanding (millions)	142.9			141.1
Dividends Declared Per Share of Common Stock	$	0.5450		$	0.5250

See Notes to Condensed Consolidated Financial Statements.

8

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited) 

	Three Months Ended March 31,
Millions of dollars	2015			2014
Net Income	$	400		$	193
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 $(2) and $1	(3		)	1
Cash flow hedging activities reclassified to interest expense, net of tax of $1 and $1	2			2
Cash flow hedging activities reclassified to gas purchased for resale, net of tax of $5 and $(2)	7			(4		)
Net unrealized gains (losses) on cash flow hedging activities	6			(1		)
Deferred cost of employee benefit plans, net of tax of $(3) and $-	(4		)	—
Other Comprehensive Income (Loss)	2			(1		)
Total Comprehensive Income	$	402		$	192

See Notes to Condensed Consolidated Financial Statements.

9

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited) 

	Three Months Ended March 31,
Millions of dollars	2015			2014
Cash Flows From Operating Activities:
Net income	$	400		$	193
Adjustments to reconcile net income to net cash provided from operating activities:
Gain on sale of subsidiaries	(353		)	—
Losses from equity method investments	1			1
Deferred income taxes, net	(74		)	7
Depreciation and amortization	100			99
Amortization of nuclear fuel	13			15
Allowance for equity funds used during construction	(5		)	(7		)
Carrying cost recovery	(3		)	(2		)
Changes in certain assets and liabilities:				—
Receivables	33			(56		)
Inventories	31			70
Prepayments	218			12
Regulatory assets	(68		)	(108		)
Regulatory liabilities	6			(94		)
Accounts payable	(67		)	29
Taxes accrued	(71		)	(143		)
Interest accrued	(7		)	(7		)
Pension and other post retirement benefits	(1		)	(2		)
Derivative financial instruments	59			39
Other assets	(6		)	11
Other liabilities	(11		)	81
Net Cash Provided From Operating Activities	195			138
Cash Flows From Investing Activities:
Property additions and construction expenditures	(352		)	(289		)
Proceeds from sale of subsidiaries	645			—
Proceeds from investments (including derivative collateral returned)	318			16
Purchase of investments (including derivative collateral posted)	(400		)	(22		)
Net Cash Provided from (Used For) Investing Activities	211			(295		)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock	14			22
Repayment of long-term debt	(158		)	(9		)
Dividends	(75		)	(66		)
Short-term borrowings, net	(293		)	184
Net Cash Provided From (Used for) Financing Activities	(512		)	131
Net Decrease In Cash and Cash Equivalents	(106		)	(26		)
Cash and Cash Equivalents, January 1	137			136
Cash and Cash Equivalents, March 31	$	31		$	110
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $3 and $3)	$	81		$	80
– Income taxes	8			100
Noncash Investing and Financing Activities:
Accrued construction expenditures	84			77
Capital leases	2			1

 See Notes to Condensed Consolidated Financial Statements.

10

SCANA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the Three Months Ended March 31, 2015 and 2014

(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, 2014. These are interim financial statements and, due to the seasonality of the Company’s business and matters that may occur during the rest of the year, the amounts reported in the Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the full year.  In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature, which are necessary for a fair statement of the results for the interim periods reported.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Plant to be Retired

SCE&G expects to retire three units that are or were coal-fired by 2020, subject to future developments in environmental regulations, among other matters. The net carrying value of these units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. The net carrying value of three previously retired units is recorded in regulatory assets within unrecovered plant (see Note 2).

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.  There were no securities considered to be dilutive potential common stock during any period presented. The Company has issued no securities that would have an antidilutive effect on earnings per share.

Asset Management and Supply Service Agreements

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities.  Such counterparties held 32% and 48% of PSNC Energy’s natural gas inventory at March 31, 2015

and December 31, 2014, respectively, with a carrying value of $8.7 million and $26.1 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, which expired on March 31, 2015, have been replaced with similar agreements that expire March 31, 2017.

Income Statement Presentation

The Company presents the revenues and expenses of its regulated businesses and its retail natural gas marketing businesses (including those activities of segments described in Note 10) within operating income, and it presents all other activities within other income (expense). Consistent with this presentation, the gain on the sale of CGT is reflected within operating income and the gain on the sale of SCI is reflected within other income (expense).

New Accounting Matters

In April 2014, the FASB issued new accounting guidance for reporting discontinued operations and disclosures of disposals of components of an entity. Under this new guidance, only those discontinued operations which represent a strategic

11

shift that will have a major effect on an entity’s operations and financial results should be reported as discontinued operations in the financial statements. As permitted, the Company adopted this new guidance for the period ended December 31, 2014.

In May 2014, the FASB 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. Currently, the Company would be required to adopt the new guidance in the first quarter of 2017, and early adoption would not be permitted. However, the FASB may defer the adoption of this guidance for one year.  The Company has not determined the impact this guidance will have on its results of operations, cash flows or financial position.

In April 2015, the FASB issued new accounting guidance intended to simplify the presentation of debt issuance costs by requiring that such costs be deducted from the carrying amounts related to debt liabilities when presented in the balance sheet. As permitted, the Company expects to early adopt this new guidance in the fourth quarter of 2015.  The Company does not expect the adoption of this guidance to have a significant impact on its financial position.  The guidance will not affect the Company’s results of operations or cash flows.

In April 2015, the FASB issued new accounting guidance related to fees paid by a customer in a cloud computing arrangement.  Among other things, the new guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. The Company expects to adopt this new guidance in the first quarter of 2016. The Company is evaluating this guidance and has not determined what impact it will have on the Company’s 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 base 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 base fuel cost increase was offset by a reduction in SCE&G's rate rider related to pension costs, which was approved by the SCPSC in March 2014. In addition, pursuant to the April 29, 2014 order, the Company's electric revenue for 2014 was reduced by approximately $46 million for adjustments to the fuel cost component and related under-collected fuel balance. Such adjustments are fully offset by the recognition within other income of gains realized from the late 2013 settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. The order also provided for 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. See also Note 6.

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. The impact of changes to the Nuclear Waste Act fee is considered during annual fuel rate proceedings.

By order dated April 30, 2015, the SCPSC approved a settlement agreement among SCE&G, the ORS, and the SCEUC in which SCE&G agreed to decrease the total fuel cost component of retail electric rates. Under this order, SCE&G is to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2015, which is estimated to be $36.1 million, over a 12-month period beginning with the first billing cycle of May 2015.

12

On February 9, 2015, SCE&G petitioned the SCPSC for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. SCE&G's DER program is structured to achieve, no later than December 31, 2020, renewable energy facilities within South Carolina with an aggregate amount of installed nameplate generating capacity equal to at least two percent of the previous five-year average of SCE&G's retail peak demand. A public hearing on this matter has been scheduled to begin on June 2, 2015.     

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, and $1.9 million and $1.2 million of such carrying costs were accrued within other income during each of the three months ended March 31, 2015 and 2014, respectively. 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 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 a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G previously identified six coal-fired units that it has subsequently retired or intends to retire by 2020, subject to future developments in environmental regulations, among other matters. Three of these units were retired by December 31, 2013, and their net carrying value 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. The net carrying value of the remaining units is included in Plant to be Retired, Net. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.

SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and net lost 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 revenues, program costs, incentives and net program benefits. The SCPSC approved recovery of the following amounts pursuant to annual DSM Programs filings, which went into effect as indicated below:

Year	Effective	Amount
2015	First billing cycle of May	$32.0 million
2014	First billing cycle of May	$15.4 million
2013	First billing cycle of May	$16.9 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 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 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 revenues as of April 30, 2014, which had been deferred within regulatory assets resulting from the May 2013 order. 

• In addition, in April 2014 the SCPSC, upon recommendation of the ORS, reduced by 25%, or $6.6 million, the amount of net lost 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

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net lost 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 recovery of the following amounts under the BLRA effective for bills rendered on and after October 30 in the following years:

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

On March 12, 2015, SCE&G petitioned the SCPSC seeking approval of an updated construction milestone schedule and capital cost schedule for the New Units. The updated construction schedule reflects new substantial completion dates for Units 2 and 3 of June 2019, and June 2020, respectively. The petition also incorporates in the construction cost schedules approximately $698 million (SCE&G’s portion in 2007 dollars) in incremental capital costs that have been identified since the last approved order in November 2012, of which $539 million (SCE&G’s portion in 2007 dollars) are associated with construction delays and other contested costs. The total project capital cost is now estimated at approximately $5.2 billion (SCE&G’s portion in 2007 dollars) or $6.8 billion including escalation and allowance for funds used during construction (SCE&G’s portion in future dollars). As noted in the petition, the construction and capital cost schedules are subject to continuing review and negotiations by the parties. In making this filing, SCE&G does not waive any claims related to delay and other related contested costs with the Consortium. A public hearing on this matter is scheduled to begin on July 21, 2015, and the SCPSC is expected to issue its order in September 2015. See Note 9.

In May 2015, SCE&G expects to file an application to recover through revised rates the financing cost of incremental construction work in progress incurred for new nuclear generation since the last rate action described above.  Any additional financing cost recovery approved by the SCPSC would be expected to  be effective for bills rendered on and after October 30, 2015.  It is expected that such rate action would be contingent upon a favorable SCPSC order on the March 2015 petition.

Gas

SCE&G

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

Year	Action			Amount
2014	0.6	%	Decrease	$2.6 million
2013	No change			-

SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. 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, 2014 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.

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.

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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.

In May 2014, the NCUC issued an order requiring utilities to adjust rates to reflect changes in the state corporate income tax rate that had been enacted by the North Carolina legislature and to file a proposal to refund amounts previously collected on a provisional basis. Pursuant to the order, PSNC Energy lowered its rates effective July 1, 2014, and refunded the amounts collected on a provisional basis through the normal operation of its Rider D rate mechanism. These amounts were not significant for any period presented.

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	March 31, 2015		December 31, 2014
Regulatory Assets:
Accumulated deferred income taxes	$	282	$	284
Under-collections - electric fuel adjustment clause	4		20
Environmental remediation costs	40		40
AROs and related funding	370		366
Franchise agreements	25		26
Deferred employee benefit plan costs	337		350
Planned major maintenance	—		2
Deferred losses on interest rate derivatives	549		453
Deferred pollution control costs	35		36
Unrecovered plant	132		137
DSM Programs	58		56
Carrying costs on deferred tax assets related to nuclear construction	11		9
Pipeline integrity management costs	10		9
Other	37		35
Total Regulatory Assets	$	1,890	$	1,823

Regulatory Liabilities:
Accumulated deferred income taxes	$	22	$	22
Asset removal costs	712		703
Storm damage reserve	6		6
Deferred gains on interest rate derivatives	82		82
Planned major maintenance	7		—
Other	—		1
Total Regulatory Liabilities	$	829	$	814

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

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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 which are expected to be recovered in retail electric rates over periods exceeding 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 25 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 and distribution 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 2020.

Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. Accordingly, in 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations 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, 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 through 2043. 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.

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 2015 SCPSC order, deferred costs are currently being recovered over approximately five years through an approved rate rider. 

Carrying costs on deferred tax assets related to nuclear construction represent accrued carrying costs on accumulated deferred income tax assets associated with the New Units which are not part of electric base rates. These carrying costs are computed using weighted average debt cost of capital and will be amortized over ten years beginning in approximately 2021.

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Pipeline integrity management costs represent costs incurred to comply with regulatory requirements related to certain natural gas pipelines located near moderate to high density populations. Such costs will be considered for recovery through rates in PSNC Energy's next general rate proceeding.

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

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

The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely. During the first quarter of 2015, no amounts were applied to offset incremental storm damage costs.

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 specifically 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.

3.COMMON EQUITY

Changes in common equity during the three months ended March 31, 2015 and 2014 were as follows:

	Common Stock						Accumulated Other Comprehensive Income (Loss)
Millions	Shares	Amount		Retained Earnings			Gains(Losses) on Cash Flow Hedges			Deferred Employee Benefit Plans			Total AOCI			Total Common Equity
Balance as of January 1, 2015	143	$	2,378	$	2,684		$	(63	)	$	(12	)	$	(75	)	$	4,987
Net Income				400												400
Other Comprehensive Income (Loss):
Losses arising during the period							(3		)	(4		)	(7		)	(7		)
Gains/amortization reclassified from AOCI							9			—			9			9
Total Comprehensive Income (Loss)				400			6			(4		)	2			402
Issuance of Common Stock	—	14														14
Dividends Declared				(78		)										(78		)
Balance as of March 31, 2015	143	$	2,392	$	3,006		$	(57	)	$	(16	)	$	(73	)	$	5,325
Balance as of January 1, 2014	141	$	2,280	$	2,444		$	(52	)	$	(8	)	$	(60	)	$	4,664
Net Income				193												193
Other Comprehensive Income:
Gains arising during the period							1			—			1			1
Losses/amortization reclassified from AOCI							(2		)	—			(2		)	(2		)
Total Comprehensive Income				193			(1		)	—			(1		)	192
Issuance of Common Stock	—	27														27
Dividends Declared				(74		)										(74		)
Balance as of March 31, 2014	141	$	2,307	$	2,563		$	(53	)	$	(8	)	$	(61	)	$	4,809

Gains and losses on cash flow hedges reclassified during the three months ended March 31, 2015 resulted in higher interest expense of $2 million and higher cost of gas purchased for resale of $7 million. Such reclassifications during the comparable period in 2014 resulted in higher interest expense of $2 million and lower cost of gas purchased for resale of $4 million.

SCANA had 200 million shares of common stock authorized as of March 31, 2015 and December 31, 2014.

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.

On February 2, 2015, SCANA redeemed prior to maturity $150 million of its 7.7% junior subordinated notes at their face value.

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

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Liquidity

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

	SCANA						SCE&G						PSNC Energy
Millions of dollars	March 31, 2015			December 31, 2014			March 31, 2015			December 31, 2014			March 31, 2015		December 31, 2014
Lines of credit:
Total committed long-term	$	300		$	300		$	1,400		$	1,400		$	100	$	100
Outstanding commercial paper (270 or fewer days)	$	15		$	179		$	610		$	709		—		30
Weighted average interest rate	0.65		%	0.54		%	0.54		%	0.52		%	—		0.65		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—		—
Available	$	282		$	118		$	790		$	691		$	100	$	70

SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million, $1.2 billion (of which $500 million relates to Fuel Company) and $100 million, respectively, which expire in October 2019. In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million, which 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 TD Bank N.A. These letters of credit expire, subject to renewal, in the fourth quarter of 2019.

5.INCOME TAXES

During 2013 and 2014, 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 $16 million. If recognized, $13 million of the tax benefit would affect the Company’s effective tax rate. It is reasonably possible that this tax benefit will increase by an additional $2 million within the next 12 months. It is also reasonably possible that this tax benefit may decrease by $7 million within the next 12 months. No other material changes in the status of the Company’s tax positions have occurred through March 31, 2015.

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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.

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 their 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

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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 not designated as cash flow hedges, and all related fair value changes and settlement amounts are recorded as regulatory assets or liabilities. Interest rate derivatives entered into before October 2013 were designated as cash flow hedges, and for such instruments only the effective portion of fair value changes and settlement amounts are recorded in regulatory assets or regulatory liabilities. Upon settlement, losses on swaps are amortized over the lives of related debt issuances, and gains are applied to under-collected fuel, are amortized to interest expense or are 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 March 31, 2015
Commodity contracts	10,140,000	5,633,000	3,528,964	19,301,964
Energy management contracts (a)	—	—	40,811,533	40,811,533
Total (a)	10,140,000	5,633,000	44,340,497	60,113,497
As of December 31, 2014
Commodity contracts	6,840,000	7,951,000	3,446,720	18,237,720
Energy management contracts (b)	—	—	37,495,339	37,495,339
Total (b)	6,840,000	7,951,000	40,942,059	55,733,059

(a)  Includes an aggregate 3,148,404 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 933,893 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 March 31, 2015 and $124.4 million at December 31, 2014. The Company was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.3 billion at March 31, 2015 and $1.1 billion at December 31, 2014.

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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 March 31, 2015
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	4
				Other deferred credits and other liabilities	33
Commodity contracts				Other current assets	1
				Derivative financial instruments	4
Total					$	42
Not designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	288
				Other deferred credits and other liabilities	30
Commodity contracts	Other current assets	$	1
Energy management contracts	Other current assets	13		Other current assets	3
				Derivative financial instruments	10
	Other deferred debits and other assets	6		Other deferred credits and other liabilities	6
Total		$	20		$	337

As of December 31, 2014
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	5
				Other deferred credits and other liabilities	28
Commodity contracts				Other current assets	1
				Derivative financial instruments	11
Total					$	45
Not designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	207
				Other deferred credits and other liabilities	17
Commodity contracts	Other current assets	$	1
Energy management contracts	Other current assets	15		Other current assets	5
				Derivative financial instruments	10
	Other deferred debits and other assets	5		Other deferred credits and other liabilities	5
Total		$	21		$	244

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 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

	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2015			2014			Location	2015	2014
Three Months Ended March 31,
Interest rate contracts	$	(2	)	$	(3	)	Interest expense	—	$	(1	)

	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	2015			2014			Location	2015			2014
Three Months Ended March 31,
Interest rate contracts	$	(2	)	$	(2	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	(1		)	3			Gas purchased for resale	(7		)	4
Total	$	(3	)	$	1			$	(9	)	$	2

As of March 31, 2015, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive income (loss) to earnings arising from cash flow hedges will include approximately $4.0 million as an increase to gas cost and approximately $6.4 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of March 31, 2015, all of the Company’s commodity cash flow hedges settle by their terms before the end of the first quarter of 2017.

As of March 31, 2015, the Company expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.3 million as an increase to interest expense, assuming financial markets remain at their current levels.

Hedge Ineffectiveness

Other losses recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in the three months ended March 31, 2015 and 2014, respectively.

Derivatives not designated as Hedging Instruments
	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2015			2014			Location	2015		2014
Three Months Ended March 31,
Interest rate contracts	$	(94	)	$	(112	)	Other income	$	4	—

As of March 31, 2015, 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 $0.7 million as an increase to other income.

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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 March 31, 2015 and December 31, 2014, the Company has posted $233.5 million and $152.4 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 March 31, 2015 and December 31, 2014, the Company could have been required to post an additional $141.7 million and $129.8 million, respectively, of collateral with its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of March 31, 2015 and December 31, 2014 is $375.2 million and $282.2 million, respectively.

As noted previously, for all periods presented, the Company did not have interest rate derivative instruments in a net asset position and did not have commodity derivatives with underlying contingent features which, if triggered, would have permitted the Company to request collateral from its counterparties. At March 31, 2015, the Company could have called on letters of credit in the amount of $3.0 million related to $19.0 million in commodity derivatives that are in a net asset position, compared to letters of credit of $9.2 million related to derivatives of $20.0 million at December 31, 2014, 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 of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position		Net Amount
Millions of dollars						Financial Instruments	Cash Collateral Received
As of March 31, 2015
Commodity contracts	$	1	—	$	1	—	—	$	1
Energy management contracts	19		—	19		—	—	19
Total	$	20	—	$	20	—	—	$	20
Balance sheet location	Other current assets			$	14
	Other deferred debits and other assets			6
	Total			$	20

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As of December 31, 2014
Commodity contracts	$	1	—	$	1	—	—	$	1
Energy management contracts	20		—	20		—	—	20
Total	$	21	—	$	21	—	—	$	21
Balance sheet location	Other current assets			$	16
	Other deferred debits and other assets			5
	Total			$	21

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

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position				Net Amount
Millions of dollars						Financial Instruments	Cash Collateral Posted
As of March 31, 2015
Interest rate contracts	$	355	—	$	355	—	$	(216	)	$	139
Commodity contracts	5		—	5		—	(4		)	1
Energy management contracts	19		—	19		—	(13		)	6
Total	$	379	—	$	379	—	$	(233	)	$	146
Balance sheet location	Other current assets			$	4
	Derivative financial instruments			306
	Other deferred credits and other liabilities			69
	Total			$	379

As of December 31, 2014
Interest rate contracts	$	257	—	$	257	—	$	(131	)	$	126
Commodity contracts	12		—	12		—	(10		)	2
Energy management contracts	20		—	20		—	(11		)	9
Total	$	289	—	$	289	—	$	(152	)	$	137
Balance sheet location	Other current assets			$	6
	Derivative financial instruments			233
	Other deferred credits and other liabilities			50
	Total			$	289

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 March 31, 2015				As of December 31, 2014
Millions of dollars	Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	$	13	—		$	13	—
Commodity contracts	1		—		1		—
Energy management contracts	—		$	19	—		$	20
Liabilities:
Interest rate contracts	—		355		—		257
Commodity contracts	—		—		1		11
Energy management contracts	3		23		5		18

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 were as follows:

	March 31, 2015				December 31, 2014
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	5,541.6	$	6,501.6	$	5,697.2	$	6,592.1

Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates.  As such, the aggregate fair values presented above are considered to be Level 2. 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	2015			2014			2015		2014
Three months ended March 31,
Service cost	$	5.8		$	5.0		$	1.4	$	1.2
Interest cost	9.5			10.2			2.9		3.1
Expected return on assets	(15.5		)	(16.8		)	—		—
Prior service cost amortization	1.0			1.0			0.1		0.1
Amortization of actuarial losses	3.5			1.3			0.6		0.1
Net periodic benefit cost	$	4.3		$	0.7		$	5.0	$	4.5

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 the Company’s results of operations, cash flows and financial position.

New Nuclear Construction

In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, 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%. As discussed below, 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.

EPC Contract and BLRA Matters

The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval 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 schedule contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, 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. As of March 31, 2015, SCE&G’s investment in the New Units totaled $2.9 billion, for which the financing costs on $2.4 billion have been reflected in rates under the BLRA.

The SCPSC granted initial approval of the construction schedule, including 146 milestones within that schedule, and related forecasted capital costs in 2009. The NRC issued COLs in March 2012. In November 2012, the SCPSC approved 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 that March 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

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modifications of the shield building and certain prefabricated structural modules for the New Units and unanticipated rock conditions at the site. In October 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal.

The substantial completion dates currently approved by the SCPSC for Units 2 and 3 are March 15, 2017 and May 15, 2018. The SCPSC also approved an 18-month contingency period beyond each of these dates, and for each of the 146 milestones in the schedule.

Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule, including those related to 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 CA01, which houses components inside the containment vessel. Module CA01 and shield building modules are considered critical path items for both New Units. The delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow CA01 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 was a revised, fully integrated project schedule with timing of specific construction activities (Revised, Fully-Integrated Construction Schedule) along with related cost information.

The Revised, Fully-Integrated Construction Schedule indicated that the substantial completion of Unit 2 was expected to occur in mid-June 2019 and that the substantial completion of Unit 3 was expected to be approximately 12 months later. SCE&G has not, however, accepted the Consortium's contention that the new substantial completion dates are made necessary by delays that are excusable under the EPC Contract. The Consortium continues to refine and update the Revised, Fully-Integrated Construction Schedule as designs are finalized, as construction progresses, and as additional information is received.

As discussed above, the milestone schedule approved by the SCPSC in November 2012 provides for 146 milestone dates, each of which is subject to an 18-month schedule contingency. As of April 30, 2015, 105 milestones have been completed, and three of the remaining milestones have not been completed within their 18-month contingency periods. In light of the Revised, Fully Integrated Schedule, it is anticipated that the completion dates for a substantial number of the remaining milestone dates will also extend beyond their contingency periods. Further, capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) are projected to exceed amounts currently approved by the SCPSC of $4.5 billion and $5.8 billion, respectively.

As such, in March 2015 SCE&G petitioned the SCPSC for an order to update the BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively. In addition, that petition included certain updated owner's costs ($245 million) and other capital costs ($453 million) which, if approved, would reset projected capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) to $5.2 billion and $6.8 billion, respectively. These projections include cost amounts related to the Revised, Fully-Integrated Construction Schedule for which SCE&G has not accepted responsibility and which may be the subject of dispute. As such, the petition does not reflect the resolution of negotiations.

The SCPSC will hold a public hearing related to the petition in July 2015. While 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, SCE&G cannot predict the outcome of this regulatory process. As discussed in Note 2, SCE&G expects the SCPSC to issue its order on the petition in September 2015.

Additional claims by the Consortium or SCE&G involving the project schedule and budget may arise as the project continues. The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve such issues. SCE&G expects to resolve all disputes (including any ultimate disagreements involving the preliminary cost estimates provided by the Consortium in the third quarter of 2014) 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.

Santee Cooper Matters

As noted above, 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

27

date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost of the percentage conveyed as of the date of each 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. Based on the current milestone schedule and capital costs schedule approved by the SCPSC in November 2012, SCE&G’s estimated cost would be approximately $500 million for the additional 5% interest being acquired from Santee Cooper. This cost figure is expected to be higher in light of the delays and related costs discussed above.

Nuclear Production Tax Credits

The IRS has 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. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion. Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on the above substantial completion dates provided by the Consortium of June 2019 and June 2020 for Units 2 and 3, respectively, both New Units are expected to be operational and to qualify for the nuclear production tax credits; however, further delays in the schedule or changes in tax law could impact such conclusions. To the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers as so realized.

Other Project Matters

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. SCE&G prepared and submitted an integrated response plan for the New Units to the NRC in August 2013. That plan is currently under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units.

Environmental

The Company's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on the Company's financial condition, results of operations and cash flows. In addition, the Company often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, the Company expects to recover such expenditures and costs through existing ratemaking provisions.

SCE&G

The EPA issued 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 proposed rule was issued 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 could be constructed without carbon capture and sequestration capabilities. The Company is evaluating the proposed rule, but does not plan to construct new coal-fired units in the near future. In addition, on June 2, 2014, the EPA issued proposed emission guidelines for states to follow in developing plans to address GHG emissions from existing units. These guidelines are expected to be made final in late summer 2015, and include state-specific rate based goals for carbon dioxide emissions.

From a regulatory perspective, SCANA, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in construction activities of the New Units which are expected to reduce GHG emission levels significantly

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once they are completed and dispatched by potentially displacing some of the current coal-fired generation sources. These actions are expected to address many of the rules and regulations discussed herein.

In July 2011, the EPA issued the CSAPR to reduce emissions of sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, thus delaying the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and annual or ozone season nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for sulfur dioxide and nitrogen oxide and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the allowances set by the CSAPR.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective.  The rule provides up to four years for generating facilities to meet the standards, and the Company's evaluation of the rule is ongoing. The Company's decision 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 MATS. On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities. SCE&G and GENCO have received a one year extension (until April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions will allow time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants that will enhance the control of certain MATS-regulated pollutants.

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 no later than September 30, 2015. Once the rule becomes effective, state regulators will modify facility NPDES permits to match more restrictive standards, thus requiring facilities to retrofit with new wastewater treatment technologies. Compliance dates will vary by type of wastewater, and some will be based on a facility's five year permit cycle and thus may range from 2018 to 2023. Based on the proposed rule, the Company expects that wastewater treatment technology retrofits will be required at Williams and Wateree Stations and may be required at other facilities.

The CWA Section 316(b) Existing Facilities Rule became effective on October 14, 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans to ensure compliance with this rule. In addition, Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones.

On April 17, 2015, the EPA's final rule for CCR was published in the Federal Register and will become effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act. In addition, this rule imposes certain requirements on ash storage ponds at SCE&G's and GENCO's generating facilities. While this rule is still being evaluated, SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds.

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. As of December 31, 2014, 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.

 The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. 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 clean-up. In addition, regulators from the EPA and other federal

29

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 by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2017 and will cost an additional $19.2 million, which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At March 31, 2015, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $35.2 million and are included in regulatory assets.

PSNC Energy

PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. 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 $1.0 million, the estimated remaining liability at March 31, 2015. 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 the parent company, a services company and other nonreportable segments that were insignificant for all periods presented. In addition, All Other includes gains from the sales of CGT and SCI (see Note 11) and their operating results and assets prior to their sale in the first quarter of 2015. CGT and SCI were nonreportable segments during all periods presented. For the period ended March 31, 2015, operating income and net income for All Other include $235 million and $202 million, respectively, related to the sales of CGT and SCI. External revenue and intersegment revenue for All Other related to CGT and SCI were not significant during any period presented.

Millions of dollars	External Revenue			Intersegment Revenue			Operating Income		Net Income
Three Months Ended March 31, 2015
Electric Operations	$	629		—			$	199	n/a
Gas Distribution	368			—			96		n/a
Retail Gas Marketing	204			—			n/a		$	27
Energy Marketing	187			$	35		n/a		6
All Other	4			114			238		207
Adjustments/Eliminations	(3		)	(149		)	53		160
Consolidated Total	$	1,389		$	—		$	586	$	400

Three Months Ended March 31, 2014
Electric Operations	$	678		$	2		$	198	n/a
Gas Distribution	455			—			97		n/a
Retail Gas Marketing	220			—			n/a		$	22
Energy Marketing	234			53			n/a		7
All Other	9			110			8		4
Adjustments/Eliminations	(6		)	(165		)	47		160
Consolidated Total	$	1,590		$	—		$	350	$	193

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	March 31,		December 31,
Segment Assets	2015		2014
Electric Operations	$	10,300	$	10,182
Gas Distribution	2,504		2,487
Retail Gas Marketing	155		140
Energy Marketing	128		150
All Other	1,494		1,474
Adjustments/Eliminations	1,825		2,419
Consolidated Total	$	16,406	$	16,852

11.    DISPOSITIONS

In December 2014, SCANA entered into definitive agreements to sell CGT and SCI. CGT is an interstate natural gas pipeline regulated by FERC that transports natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provides fiber optic communications and other services and builds, manages and leases communications towers in several southeastern states, and it was sold to a subsidiary of Spirit Communications. These sales closed in the first quarter of 2015. The pre-tax gain on the sales recognized during the first quarter of 2015 was approximately $342 million. As further described in Note 1, the pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the consolidated income statement.

CGT and SCI operate principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. In addition, neither CGT nor SCI met accounting criteria for disclosure as a reportable segment and were included within All Other in Note 10. The sales of CGT and SCI did not represent a strategic shift that will have a major effect on SCANA's operations; therefore, these sales do not meet the criteria for classification as discontinued operations.

The carrying values of the major classes of assets and liabilities classified as held for sale in the consolidated balance sheet as of December 31, 2014, were as follows:

Millions of dollars	CGT		SCI		Total
Assets Held for Sale
Utility Plant, Net	$	288.4	—		$	288.4
Nonutility Property and Investments, Net	0.6		$	40.1	40.7
Current Assets	6.5		3.9		10.4
Deferred Debits and Other Assets	0.9		0.2		1.1
Total Assets Held for Sale	296.4		44.2		340.6
Liabilities Held for Sale
Current Liabilities	$	3.5	$	2.2	$	5.7
Deferred Credits and Other Liabilities	42.9		3.1		46.0
Total Liabilities Held for Sale	$	46.4	$	5.3	$	51.7

31

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, 2014.

RESULTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2015

AS COMPARED TO THE CORRESPONDING PERIOD IN 2014

Earnings Per Share

The Company reports earnings as determined in accordance with accounting principles generally accepted in the United States of America (GAAP). Management believes that, in addition to reported earnings under GAAP, the Company's GAAP-adjusted weather-normalized net earnings provides a meaningful representation of its fundamental earnings power and can aid in performing period-over-period financial analysis and comparison with peer group data. In management's opinion, in addition to operating income for regulated businesses, GAAP-adjusted weather-normalized net earnings is a useful indicator of the financial results of the Company's primary businesses. This measure is also a basis for management's provision of earnings guidance and growth projections, and it is used by management in making resource allocation and other budgetary and operational decisions including determining eligibility for certain incentive compensation payments. This non-GAAP performance measure is not intended to replace the GAAP measure of net earnings, but is offered as a supplement to it. A reconciliation of reported (GAAP) earnings per share to GAAP-adjusted weather-normalized net earnings per share is provided in the table below:

	2015		2014
Reported (GAAP) earnings per share	$	2.80	$	1.37
Deduct:
Gain on sale of CGT	0.95		—
Gain on sale of SCI	0.46		—
SCE&G Electric - effect of abnormal weather	0.05		0.10
GAAP-adjusted weather-normalized net earnings per share	$	1.34	$	1.27

Earnings per share on a GAAP basis increased primarily due to gains on the sales of CGT and SCI, higher electric margins (resulting primarily from the customer growth and base rate increases under the BLRA), and lower operation and maintenance expenses. These increases were partially offset by lower gas margins, higher property taxes, higher interest cost, and dilution from additional shares outstanding, as further discussed below.

Discussion of above adjustments:

The sales of CGT and SCI were closed in the first quarter of 2015. These subsidiaries operated principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. Therefore, CGT and SCI were not a part of the Company's core business. See Note 11 to the condensed consolidated financial statements.

SCE&G estimates the effects of abnormal weather on its electric business by comparing actual temperatures in its service territory to a 15-year rolling average of temperatures. The result is used in developing an estimate of electric margin revenue, using average margin rates, attributable to the effects of abnormal weather.

Management believes that all of the above adjustments are appropriate in determining the non-GAAP financial performance measure. Such non-GAAP measure reflects management's decision that wholesale gas transportation and telecommunications operations were not a part of the Company's core businesses and would not align with the Company's

32

commitment to serve retail customers on a long-term basis. The non-GAAP measure also provides a consistent basis upon which to measure performance by excluding the effects on per share earnings of abnormal weather in the electric business.

Dividends Declared

SCANA’s Board of Directors has declared the following dividends on common stock during 2015:

Declaration Date	Dividend Per Share	Record Date	Payment Date
February 20, 2015	$0.5450	March 10, 2015	April 1, 2015
April 30, 2015	$0.5450	June 10, 2015	July 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:

Millions of dollars	2015		Change		2014
Operating revenues	$	630.3	(7.3	)%	$	679.9
Less:  Fuel used in generation	174.5		(18.4	)%	213.8
Purchased power	12.8		(48.8	)%	25.0
Margin	$	443.0	0.4	%	$	441.1

Electric margin increased primarily due to base rate increases under the BLRA ($16.0 million) and residential and commercial customer growth ($4.0 million).  These increases were mostly offset by the effects of weather ($10.4 million), lower industrial margins ($4.1 million), lower residential and commercial average use ($0.7 million) and lower collections under the Company’s rate rider for pension costs ($2.6 million). The effects on electric margin of changes in the pension rider are offset by changes in other operating expenses.

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

Classification	2015	Change		2014
Residential	2,092	(2.7	)%	2,151
Commercial	1,715	(2.0	)%	1,750
Industrial	1,468	1.0	%	1,453
Other	140	—	%	140
Total Retail Sales	5,415	(1.4	)%	5,494
Wholesale	246	0.8	%	244
Total Sales	5,661	(1.3	)%	5,738

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

Gas Distribution

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

Millions of dollars	2015		Change		2014
Operating revenues	$	368.1	(19.1	)%	$	455.2
Less:  Gas purchased for resale	204.7		(30.0	)%	292.5
Margin	$	163.4	0.4	%	$	162.7

33

Margin increased primarily due to residential and commercial customer growth of $3.6 million. These increases were partially offset by lower average usage at SCE&G of $1.0 million and a SCPSC-approved decrease in retail gas base rates under the RSA which became effective in November 2014 at SCE&G of $1.8 million.

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

Classification (in thousands)	2015	Change		2014
Residential	24,480	(5.8	)%	25,981
Commercial	11,992	(6.1	)%	12,767
Industrial	5,130	(3.8	)%	5,333
Transportation	10,169	0.6	%	10,106
Total	51,771	(4.5	)%	54,187

Residential and commercial firm sales volumes decreased due to the effects of weather and lower average use. These decreases were partially offset by customer growth. Commercial and industrial interruptible volumes decreased due to curtailments at SCE&G. Transportation volumes increased due to customers shifting to transportation only service, partially offset by a transportation customer being offline for most of the first quarter of 2015 at PSNC Energy.

Retail Gas Marketing

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

Millions of dollars	2015		Change		2014
Operating revenues	$	204.7	(7.0	)%	$	220.2
Net income	26.9		20.6	%	22.3

Operating revenues decreased in 2015 due to lower demand. Net income increased in 2015 due to lower commodity costs and lower bad debt expense related primarily to lower revenues.

Energy Marketing

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

Millions of dollars	2015		Change		2014
Operating revenues	$	221.4	(22.8	)%	$	286.7
Net income	5.6		(13.8	)%	6.5

Operating revenues decreased due to lower market prices and lower demand. Net income declined due to higher transportation costs. 

Other Operating Expenses

Other operating expenses were as follows:

	Third Quarter
Millions of dollars	2015		Change		2014
Other operation and maintenance	$	172.5	(4.3	)%	$	180.3
Depreciation and amortization	96.1		1.3	%	94.9
Other taxes	59.4		3.1	%	57.6

Other operation and maintenance expenses decreased primarily due to lower labor expenses (including effects of the lower pension rider) of $5.0 million, lower storm expenses of $2.2 million and by $3.9 million due to the sale of CGT. These decreases were partially offset byhigher electric operating expenses of $1.7 million, DSM Programs cost amortization of $0.3

34

million, and other general expenses of $0.7 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. Excluding the effects of the gain on the sale of SCI, other income (expense) increased primarily due to the recognition in the first quarter of 2015, pursuant to SCPSC orders, of $4.4 million of gains realized upon the late 2013 settlement of certain interest rate derivative contracts which were previously recorded as regulatory liabilities.Such gain recognition was offset by downward adjustments to revenues in connection with SCE&G's DSM Programs reflected within electric margin.

AFC decreased in 2015 due to lower AFC rates.

Interest Expense

     Interest charges increased primarily due to increased borrowings.

Income Taxes

Income taxes for the three months ended March 31, 2015 were higher than for the same period in 2014 primarily due to higher income before taxes. Income before taxes was higher in 2015 primarily due to the sale of CGT and SCI. The effective tax rate for 2015 was higher than the rate for 2014 primarily due to discrete tax items related to the sales of CGT and SCI.

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its cash obligations will be met through internally generated funds and additional short- and long-term borrowings. The Company expects that, barring a future impairment of the capital markets, it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future, including the cash requirements for nuclear construction and refinancing maturing long-term debt.  The Company’s ratio of earnings to fixed charges for the three and 12 months ended March 31, 2015 was 8.70 and 4.42, 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 TD Bank N.A.  The letters of credit expire, subject to renewal, in the fourth quarter of 2019.

At March 31, 2015, the Company had net available liquidity of approximately $1.2 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 remainder is 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 18 years at a weighted average effective interest rate 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.

SCE&G has obtained FERC authority to issue short-term indebtedness and to assume liabilities as a guarantor(pursuant to Section 204 of the Federal Power Act). SCE&G may issue unsecured promissory notes, commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, banks, and dealers in commercial paper in amounts not to exceed $600 million. GENCO has obtained FERC authority to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2016.

On January 29, 2015, SCANA entered into an unsecured, three-month credit agreement in the amount of $150 million. SCANA entered this agreement to ensure sufficient liquidity was available to redeem its Junior Subordinated Notes on February 2, 2015. No borrowings were made under this agreement, and it expired according to its terms on February 6, 2015.

35

On February 2, 2015, SCANA redeemed prior to maturity $150 million of its 7.70% junior subordinated notes at their face value.

SCANA issued approximately $14 million of common stock during the three months ended March 31, 2015 through various compensation and dividend reinvestment plans. 

SCE&G's current preliminary estimates of its capital expenditures for new nuclear construction (including transmission) for 2015 through 2017, which are subject to continuing review and adjustment, are $940 million in 2015, $1,007 million in 2016, and $899 million in 2017.

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 DER 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. On March 30, 2015, the SCPSC approved a net energy metering methodology. A hearing before the SCPSC related to specific DER programs proposed by SCE&G is scheduled to begin June 2, 2015.

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. SCANA Energy submitted a bid 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 second 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 three months ended March 31, 2015 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.

36

	Expected Maturity			Expected Maturity
Futures - Long	2015	2016	Options Purchased Call - Long	2015	2016
Settlement Price (a)	2.82	3.13	Strike Price (a)	3.74	3.72
Contract Amount (b)	12.9	4.6	Contract Amount (b)	19.1	18.8
Fair Value (b)	10.0	4.2	Fair Value (b)	0.4	1.1
Futures - Short	2015	2016
Settlement Price (a)	2.79	3.15
Contract Amount (b)	0.3	1.3
Fair Value (b)	0.2	1.3
(a)  Weighted average, in dollars
(b)  Millions of dollars

	Expected Maturity
Swaps	2015	2016	2017	2018
Commodity Swaps:
Pay fixed/receive variable (b)	49.9	28.5	6.4	3.6
Average pay rate (a)	3.7910	3.9134	4.1944	4.2421
Average received rate (a)	2.8203	3.1318	3.3684	3.4496
Fair value (b)	37.1	22.8	5.1	2.9
Pay variable/receive fixed (b)	29.8	17.2	5.0	2.9
Average pay rate (a)	2.7972	3.1204	3.3654	3.4496
Average received rate (a)	3.8441	4.0833	4.2136	4.2471
Fair value (b)	41.0	22.6	6.3	3.6
Basis Swaps:
Pay variable/receive variable (b)	7.2	1.0	0.9	—
Average pay rate (a)	2.8008	3.1763	3.4030	—
Average received rate (a)	2.7742	3.1592	3.4084	—
Fair value (b)	7.1	1.0	0.9	—
(a) Weighted average, in dollars
(b) Millions of dollars

ITEM 4. CONTROLS AND PROCEDURES

As of March 31, 2015, SCANA conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of (a) the effectiveness of the design and operation of its disclosure controls and procedures and (b) any change in its internal control over financial reporting.  Based on this evaluation, the CEO and CFO concluded that, as of March 31, 2015, SCANA’s disclosure controls and procedures were effective.  There has been no change in SCANA’s internal control over financial reporting during the quarter ended March 31, 2015 that has materially affected or is reasonably likely to materially affect SCANA’s internal control over financial reporting.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY FINANCIAL SECTION

ITEM 1.    FINANCIAL STATEMENTS

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

Millions of dollars	March 31, 2015			December 31, 2014
Assets
Utility Plant In Service	$	10,739		$	10,650
Accumulated Depreciation and Amortization	(3,716		)	(3,667		)
Construction Work in Progress	3,451			3,302
Plant to be Retired, Net	164			169
Nuclear Fuel, Net of Accumulated Amortization	317			329
Utility Plant, Net ($716 and $675 related to VIEs)	10,955			10,783
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	67			67
Assets held in trust, net-nuclear decommissioning	115			113
Other investments	2			2
Nonutility Property and Investments, Net	184			182
Current Assets:
Cash and cash equivalents	10			100
Receivables, net of allowance for uncollectible accounts of $3 and $4	490			524
Affiliated receivables	19			109
Inventories (at average cost):
Fuel and gas supply	119			131
Materials and supplies	131			129
Prepayments	79			154
Other current assets	170			99
Total Current Assets ($121 and $158 related to VIEs)	1,018			1,246
Deferred Debits and Other Assets:
Pension asset	11			10
Regulatory assets	1,817			1,745
Other	149			141
Total Deferred Debits and Other Assets ($45 and $50 related to VIEs)	1,977			1,896
Total	$	14,134		$	14,107

See Notes to Condensed Consolidated Financial Statements.

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Millions of dollars	March 31, 2015			December 31, 2014
Capitalization and Liabilities
Common Stock - no par value, 40.3 million shares outstanding	$	2,556		$	2,560
Retained Earnings	2,130			2,077
Accumulated Other Comprehensive Loss	(3		)	(3		)
Total Common Equity	4,683			4,634
Noncontrolling Interest	126			123
Total Equity	4,809			4,757
Long-Term Debt, net	4,293			4,299
Total Capitalization	9,102			9,056
Current Liabilities:
Short-term borrowings	610			709
Current portion of long-term debt	10			10
Accounts payable	181			294
Affiliated payables	365			180
Customer deposits and customer prepayments	66			61
Taxes accrued	120			170
Interest accrued	57			64
Dividends declared	71			74
Derivative financial instruments	289			208
Other	45			99
Total Current Liabilities	1,814			1,869
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,703			1,696
Deferred investment tax credits	27			28
Asset retirement obligations	539			536
Postretirement benefits	220			195
Regulatory liabilities	621			610
Other	108			117
Total Deferred Credits and Other Liabilities	3,218			3,182
Commitments and Contingencies (Note 9)	—			—
Total	$	14,134		$	14,107

See Notes to Condensed Consolidated Financial Statements.

39

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited) 

	Three Months Ended
	March 31,
Millions of dollars	2015			2014
Operating Revenues:
Electric	$	630		$	680
Gas	142			179
Total Operating Revenues	772			859
Operating Expenses:
Fuel used in electric generation	174			214
Purchased power	13			25
Gas purchased for resale	74			109
Other operation and maintenance	139			142
Depreciation and amortization	80			78
Other taxes	55			52
Total Operating Expenses	535			620
Operating Income	237			239
Other Income (Expense):
Other income	9			3
Other expense	(8		)	(6		)
Interest charges, net of allowance for borrowed funds used during construction of $3 and $3	(59		)	(56		)
Allowance for equity funds used during construction	5			5
Total Other Income (Expense)	(53		)	(54		)
Income Before Income Tax Expense	184			185
Income Tax Expense	58			59
Net Income	126			126
Net Income Attributable to Noncontrolling Interest	(4		)	(3		)
Earnings Available to Common Shareholder	$	122		$	123
Dividends Declared on Common Stock	$	71		$	64

See Notes to Condensed Consolidated Financial Statements.

40

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
Millions of dollars	2015			2014
Net Income	$	126		$	126
Total Comprehensive Income	126			126
Comprehensive income attributable to noncontrolling interest	(4		)	(3		)
Comprehensive income available to common shareholder	$	122		$	123

See Notes to Condensed Consolidated Financial Statements.

41

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
Millions of dollars	2015			2014
Cash Flows From Operating Activities:
Net income	$	126		$	126
Adjustments to reconcile net income to net cash provided from operating activities:
Losses from equity method investments	1			1
Deferred income taxes, net	7			5
Depreciation and amortization	82			78
Amortization of nuclear fuel	13			15
Allowance for equity funds used during construction	(5		)	(5		)
Carrying cost recovery	(3		)	(2		)
Changes in certain assets and liabilities:
Receivables	22			(23		)
Inventories	—			19
Prepayments	75			7
Regulatory assets	(74		)	(107		)
Regulatory liabilities	6			(94		)
Accounts payable	(20		)	27
Taxes accrued	(50		)	(127		)
Interest accrued	(7		)	(11		)
Pension and other post retirement benefits	22			(2		)
Derivative financial instruments	81			40
Other assets	(3		)	15
Other liabilities	(49		)	81
Net Cash Provided From Operating Activities	224			43
Cash Flows From Investing Activities:
Property additions and construction expenditures	(319		)	(260		)
Proceeds from investments (including derivative collateral returned)	274			4
Purchase of investments (including derivative collateral posted)	(356		)	(9		)
Investment in affiliate	80			—
Net Cash Used For Investing Activities	(321		)	(265		)
Cash Flows From Financing Activities:
Repayment of long-term debt	(8		)	(9		)
Dividends	(74		)	(62		)
Contributions (to) from parent	(4		)	20
Short-term borrowings –affiliate, net	192			7
Short-term borrowings, net	(99		)	206
Net Cash Provided From Financing Activities	7			162
Net Decrease In Cash and Cash Equivalents	(90		)	(60		)
Cash and Cash Equivalents, January 1	100			92
Cash and Cash Equivalents, March 31	$	10		$	32
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $3 and $3)	$	62		$	62
– Income taxes paid (received)	(83		)	59
Noncash Investing and Financing Activities:
Accrued construction expenditures	76			97
Capital leases	2			1

See Notes to Condensed Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the Three Months Ended March 31, 2015 and 2014

(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, 2014.  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 has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, the accompanying condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. Accordingly, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements.

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $498 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances. See also Note 4.

Plant to be Retired

SCE&G expects to retire three units that are or were coal-fired by 2020, subject to future developments in environmental regulations, among other matters. The net carrying value of these units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. The net carrying value of three previously retired units is recorded in regulatory assets within unrecovered plant (see Note 2).

New Accounting Matters

In May 2014, the FASB 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. Currently, Consolidated SCE&G would be required to adopt the new guidance in the first quarter of 2017, and early adoption would not be permitted. However, the FASB may defer the adoption of this guidance for one year.  Consolidated SCE&G has not determined the impact this guidance will have on its results of operations, cash flows or financial position.

In April 2015, the FASB issued new accounting guidance intended to simplify the presentation of debt issuance costs by requiring that such costs be deducted from the carrying amounts related to debt liabilities when presented in the balance

43

sheet. As permitted, Consolidated SCE&G expects to early adopt this new guidance in the fourth quarter of 2015.  Consolidated SCE&G does not expect the adoption of this guidance to have a significant impact on its financial position.  The guidance will not affect Consolidated SCE&G’s results of operations or cash flows.

In April 2015, the FASB issued new accounting guidance related to fees paid by a customer in a cloud computing arrangement.  Among other things, the new guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. Consolidated SCE&G expects to adopt this new guidance in the first quarter of 2016. Consolidated SCE&G is evaluating this guidance and has not determined what impact it 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. 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 base 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 base fuel cost increase was offset by a reduction in SCE&G's rate rider related to pension costs, which was approved by the SCPSC in March 2014. In addition, pursuant to the April 29, 2014 order, SCE&G's electric revenue for 2014 was reduced by approximately $46 million for adjustments to the fuel cost component and related under-collected fuel balance. Such adjustments are fully offset by the recognition within other income of gains realized from the late 2013 settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. The order also provided for 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. See also Note 6.

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. The impact of changes to the Nuclear Waste Act fee is considered during annual fuel rate proceedings.

By order dated April 30, 2015, the SCPSC approved a settlement agreement among SCE&G, the ORS, and the SCEUC in which SCE&G agreed to decrease the total fuel cost component of its retail electric rates. Under this order, SCE&G is to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2015, which is estimated to be $36.1 million, over a 12-month period beginning with the first billing cycle of May 2015.

On February 9, 2015, SCE&G petitioned the SCPSC for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. SCE&G's DER program is structured to achieve, no later than December 31, 2020, renewable energy facilities within South Carolina with an aggregate amount of installed nameplate generating capacity equal to at least two percent of the previous five-year average of SCE&G's retail peak demand. A public hearing on this matter has been scheduled to begin on June 2, 2015.

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, and $1.9 million and $1.2 million of such carrying costs were accrued within other income during each of the three months ended March 31, 2015 and 2014, respectively. SCE&G

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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 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 a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G previously identified six coal-fired units that it has subsequently retired or intends to retire by 2020, subject to future developments in environmental regulations, among other matters. Three of these units were retired by December 31, 2013, and their net carrying value 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. The net carrying value of the remaining units is included in Plant to be Retired, Net. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.

SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and net lost 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 revenues, program costs, incentives and net program benefits. The SCPSC approved recovery of the following amounts pursuant to annual DSM Programs filings, which went into effect as indicated below:

Year	Effective	Amount
2015	First billing cycle of May	$32.0 million
2014	First billing cycle of May	$15.4 million
2013	First billing cycle of May	$16.9 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 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 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 revenues as of April 30, 2014, which had been deferred within regulatory assets resulting from the May 2013 order. 

• In addition, in April 2014 the SCPSC, upon recommendation of the ORS, reduced by 25%, or $6.6 million, the amount of net lost 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 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 recovery of the following amounts under the BLRA effective for bills rendered on and after October 30 in the following years:

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

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On March 12, 2015, SCE&G petitioned the SCPSC seeking approval of an updated construction milestone schedule and capital cost schedule for the New Units. The updated construction schedule reflects new substantial completion dates for Units 2 and 3 of June 2019, and June 2020, respectively. The petition also incorporates in the construction cost schedules approximately $698 million (SCE&G’s portion in 2007 dollars) in incremental capital costs that have been identified since the last approved order in November 2012, of which $539 million (SCE&G’s portion in 2007 dollars) are associated with construction delays and other contested costs. The total project capital cost is now estimated at approximately $5.2 billion (SCE&G’s portion in 2007 dollars) or $6.8 billion including escalation and allowance for funds used during construction (SCE&G’s portion in future dollars). As noted in the petition, the construction and capital cost schedules are subject to continuing review and negotiations by the parties. In making this filing, SCE&G does not waive any claims related to delay and other related contested costs with the Consortium. A public hearing on this matter is scheduled to begin on July 21, 2015, and the SCPSC is expected to issue its order in September 2015. See Note 9.

In May 2015, SCE&G expects to file an application to recover through revised rates the financing cost of incremental construction work in progress incurred for new nuclear generation since the last rate action described above.  Any additional financing cost recovery approved by the SCPSC would be expected to  be effective for bills rendered on and after October 30, 2015.  It is expected that such rate action would be contingent upon a favorable SCPSC order on the March 2015 petition.

Gas

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

Year	Action			Amount
2014	0.6	%	Decrease	$2.6 million
2013	No change			-

SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. 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, 2014 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.

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	March 31, 2015		December 31, 2014
Regulatory Assets:
Accumulated deferred income taxes	$	276	$	278
Under collections – electric fuel adjustment clause	4		20
Environmental remediation costs	35		36
AROs and related funding	350		347
Franchise agreements	25		26
Deferred employee benefit plan costs	305		310
Planned major maintenance	—		2
Deferred losses on interest rate derivatives	549		453
Deferred pollution control costs	35		36
Unrecovered plant	132		137
DSM Programs	58		56
Carrying costs on deferred tax assets related to nuclear construction	11		9
Other	37		35
Total Regulatory Assets	$	1,817	$	1,745

Regulatory Liabilities:
Accumulated deferred income taxes	$	16	$	17
Asset removal costs	510		505
Storm damage reserve	6		6
Deferred gains on interest rate derivatives	82		82
Planned major maintenance	7		—
Total Regulatory Liabilities	$	621	$	610

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 which are expected to be recovered in retail electric rates over periods exceeding 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 25 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 and distribution 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 2020.

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 pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. Accordingly, in 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations 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.

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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, 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 through 2043. 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.

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 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 2015 SCPSC order, deferred costs are currently being recovered over approximately five years through an approved rate rider. 

Carrying costs on deferred tax assets related to nuclear construction represent accrued carrying costs on accumulated deferred income tax assets associated with the New Units which are not part of electric base rates. These carrying costs are computed using weighted average debt cost of capital and will be amortized over ten years beginning in approximately 2021.

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

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

The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely. During the first quarter of 2015, no amounts were applied to offset incremental storm damage costs.

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 specifically approved for recovery by the SCPSC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by SCE&G. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, Consolidated SCE&G could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on Consolidated SCE&G's results of operations, liquidity or financial position in the period the write-off would be recorded.

3. EQUITY

Changes in common equity during the three months ended March 31, 2015 and 2014 were as follows:

	Common Stock				Retained			Accumulated Other Comprehensive			Noncontrolling			Total
Millions	Shares	Amount			Earnings			Income (Loss)			Interest			Equity
Balance at January 1, 2015	40	$	2,560		$	2,077		$	(3	)	$	123		$	4,757
Earnings available to common shareholder					122						4			126
Deferred cost of employee benefit plans								—						—
Total Comprehensive Income					122			—			4			126
Capital returned to parent		(4		)										(4		)
Cash dividend declared					(69		)				(1		)	(70		)
Balance at March 31, 2015	40	$	2,556		$	2,130		$	(3	)	$	126		$	4,809
Balance at January 1, 2014	40	$	2,479		$	1,896		$	(3	)	$	117		$	4,489
Earnings available to common shareholder					123						3			126
Deferred cost of employee benefit plans								—						—
Total Comprehensive Income					123			—			3			126
Capital contributions from parent		20												20
Cash dividend declared					(62		)				(2		)	(64		)
Balance at March 31, 2014	40	$	2,499		$	1,957		$	(3	)	$	118		$	4,571

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SCE&G had 50 million shares of common stock authorized as of March 31, 2015 and December 31, 2014. SCE&G had 20 million shares of preferred stock authorized as of March 31, 2015 and December 31, 2014, 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.

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	March 31, 2015			December 31, 2014
Lines of credit:
Total committed long-term	$	1,400		$	1,400
Outstanding commercial paper (270 or fewer days)	$	610		$	709
Weighted average interest rate	0.54		%	0.52		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	790		$	691

SCE&G and Fuel Company are parties to five-year credit agreements in the amount of $1.2 billion (of which $500 million relates to Fuel Company), which expire in October 2019. In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million, which 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 TD Bank N.A. These letters of credit expire, subject to renewal, in the fourth quarter of 2019.

Consolidated SCE&G participates in a utility money pool with SCANA and certain other subsidiaries of SCANA. 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 March 31, 2015, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $275.5 million. At December 31, 2014, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $83.0 million and money pool investments due from an affiliate of $80.0 million.

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5. INCOME TAXES

During 2013 and 2014, SCANA amended certain of its 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 $16 million. If recognized, $13 million of the tax benefit would affect Consolidated SCE&G’s effective tax rate. It is reasonably possible that this tax benefit will increase by an additional $2 million within the next 12 months. It is also reasonably possible that this tax benefit may decrease by $7 million within the next 12 months. No other material changes in the status of Consolidated SCE&G’s tax positions have occurred through March 31, 2015.

                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.

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 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 their 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 not designated as cash flow hedges, and all related fair value changes and settlement amounts are recorded as regulatory assets or liabilities. Interest rate derivatives entered into before October 2013 were designated as cash flow hedges, and for such instruments only the effective portion of fair value changes and settlement amounts are recorded in regulatory assets or regulatory liabilities. Upon settlement, losses on swaps are amortized over the lives of related debt issuances, and gains are applied to under-collected fuel, are amortized to interest expense or are 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

GENCO was party to an interest rate swap designated as a cash flow hedge with a notional amount of $36.4 million at March 31, 2015 and $36.4 million at December 31, 2014. SCE&G was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.3 billion at March 31, 2015 and $1.1 billion at December 31, 2014, respectively.

The fair value of interest rate derivatives (each of which was a liability derivative for all periods presented) was reflected in the condensed consolidated balance sheet as follows:

Fair Values of Derivative Instruments	Liability Derivatives
	Balance Sheet	Fair
Millions of dollars	Location	Value
As of March 31, 2015
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	1
	Other deferred credits and other liabilities	10
Total		$	11
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	288
	Other deferred credits and other liabilities	30
Total		$	318
As of December 31, 2014
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	1
	Other deferred credits and other liabilities	8
Total		$	9
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	207
	Other deferred credits and other liabilities	17
Total		$	224

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

Derivatives in Cash Flow Hedging Relationships	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2015			2014			Location	2015	2014
Three Months Ended March 31,
Interest rate contracts	$	(2	)	$	(3	)	Interest expense	—	$	(1	)

As of March 31, 2015, Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.3 million as an increase to interest expense, assuming financial markets remain at their current levels.

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 ended March 31, 2015 and 2014, respectively.

Derivatives not designated as Hedging Instruments	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2015			2014			Location	2015		2014
Three Months Ended March 31,
Interest rate contracts	$	(94	)	$	(112	)	Other income	$	4	—

As of March 31, 2015, 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 $0.7 million as an increase to other income.

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 March 31, 2015 and December 31, 2014, Consolidated SCE&G has posted $188.6 million and $107.1 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 March 31, 2015 and December 31, 2014, Consolidated SCE&G could have been required to post an additional $140.7 million and $125.9 million, respectively, of collateral with its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of March 31, 2015 and December 31, 2014 is $329.3 million and $233.0 million, respectively.

As noted previously, Consolidated SCE&G did not have interest rate derivatives in a net asset position for any period presented.

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

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position				Net Amount
Millions of dollars						Financial Instruments	Cash Collateral Posted
As of March 31, 2015
Interest rate contracts	$	329	—	$	329	—	$	(189	)	$	140
Balance Sheet Location	Derivative financial instruments			$	289
	Other deferred credits and other liabilities			40
	Total			$	329

As of December 31, 2014
Interest rate contracts	$	233	—	$	233	—	$	(107	)	$	126
Balance Sheet Location	Derivative financial instruments			$	208
	Other deferred credits and other liabilities			25
				$	233

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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.  These fair values are considered to be Level 2. The fair value of derivative liabilities were $329 million at March 31, 2015 and $233 million at December 31, 2014. Consolidated SCE&G did not have derivative assets for any period presented.

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 were as follows:

	March 31, 2015				December 31, 2014
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,303.3	$	5,119.2	$	4,308.6	$	5,070.9

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 retired employees.  Components of net periodic benefit cost recorded by Consolidated SCE&G were as follows:

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2015			2014			2015		2014
Three months ended March 31,
Service cost	$	4.6		$	4.0		$	1.1	$	1.0
Interest cost	8.0			8.6			2.3		2.4
Expected return on assets	(13.0		)	(14.2		)	—		—
Prior service cost amortization	0.8			0.9			0.1		0.1
Amortization of actuarial losses	3.0			1.1			0.4		0.1
Net periodic benefit cost	$	3.4		$	0.4		$	3.9	$	3.6

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

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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

In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, 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%. As discussed below, 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.

EPC Contract and BLRA Matters

The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval 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 schedule contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, 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. As of March 31, 2015, SCE&G’s investment in the New Units totaled $2.9 billion, for which the financing costs on $2.4 billion have been reflected in rates under the BLRA.

The SCPSC granted initial approval of the construction schedule, including 146 milestones within that schedule, and related forecasted capital costs in 2009. The NRC issued COLs in March 2012. In November 2012, the SCPSC approved 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 that March 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 prefabricated structural modules for the New Units and unanticipated rock conditions at the site. In October 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal.

The substantial completion dates currently approved by the SCPSC for Units 2 and 3 are March 15, 2017 and May 15, 2018. The SCPSC also approved an 18-month contingency period beyond each of these dates, and for each of the 146 milestones in the schedule.

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Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule, including those related to 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 CA01, which houses components inside the containment vessel. Module CA01 and shield building modules are considered critical path items for both New Units. The delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow CA01 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 was a revised, fully integrated project schedule with timing of specific construction activities (Revised, Fully-Integrated Construction Schedule) along with related cost information.

The Revised, Fully-Integrated Construction Schedule indicated that the substantial completion of Unit 2 was expected to occur in mid-June 2019 and that the substantial completion of Unit 3 was expected to be approximately 12 months later. SCE&G has not, however, accepted the Consortium's contention that the new substantial completion dates are made necessary by delays that are excusable under the EPC Contract. The Consortium continues to refine and update the Revised, Fully-Integrated Construction Schedule as designs are finalized, as construction progresses, and as additional information is received.

As discussed above, the milestone schedule approved by the SCPSC in November 2012 provides for 146 milestone dates, each of which is subject to an 18-month schedule contingency. As of April 30, 2015, 105 milestones have been completed, and three of the remaining milestones have not been completed within their 18-month contingency periods. In light of the Revised, Fully Integrated Schedule, it is anticipated that the completion dates for a substantial number of the remaining milestone dates will also extend beyond their contingency periods. Further, capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) are projected to exceed amounts currently approved by the SCPSC of $4.5 billion and $5.8 billion, respectively.

As such, in March 2015 SCE&G petitioned the SCPSC for an order to update the BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively. In addition, that petition included certain updated owner's costs ($245 million) and other capital costs ($453 million) which, if approved, would reset projected capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) to $5.2 billion and $6.8 billion, respectively. These projections include cost amounts related to the Revised, Fully-Integrated Construction Schedule for which SCE&G has not accepted responsibility and which may be the subject of dispute. As such, the petition does not reflect the resolution of negotiations.

The SCPSC will hold a public hearing related to the petition in July 2015. While 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, SCE&G cannot predict the outcome of this regulatory process. As described in Note 2, SCE&G expects the SCPSC to issue its order on the petition in September 2015.

Additional claims by the Consortium or SCE&G involving the project schedule and budget may arise as the project continues. The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve such issues. SCE&G expects to resolve all disputes (including any ultimate disagreements involving the preliminary cost estimates provided by the Consortium in the third quarter of 2014) 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.

Santee Cooper Matters

As noted above, 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, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost of the percentage conveyed as of the date of each 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. Based on the current milestone schedule and capital costs schedule approved by the SCPSC in November

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2012, SCE&G’s estimated cost would be approximately $500 million for the additional 5% interest being acquired from Santee Cooper. This cost figure is expected to be higher in light of the delays and related costs discussed above.

Nuclear Production Tax Credits

The IRS has 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. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion. Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on the above substantial completion dates provided by the Consortium of June 2019 and June 2020 for Units 2 and 3, respectively, both New Units are expected to be operational and to qualify for the nuclear production tax credits; however, further delays in the schedule or changes in tax law could impact such conclusions. To the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers as so realized.

Other Project Matters

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. SCE&G prepared and submitted an integrated response plan for the New Units to the NRC in August 2013. That plan is currently under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units.

Environmental

Consolidated SCE&G's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on Consolidated SCE&G's financial condition, results of operations and cash flows. In addition, Consolidated SCE&G often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, Consolidated SCE&G expects to recover such expenditures and costs through existing ratemaking provisions.

The EPA issued 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 proposed rule was issued 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 could be constructed without carbon capture and sequestration capabilities. Consolidated SCE&G is evaluating the proposed rule, but does not plan to construct new coal-fired units in the near future. In addition, on June 2, 2014, the EPA issued proposed emission guidelines for states to follow in developing plans to address GHG emissions from existing units. These guidelines are expected to be made final in late summer 2015, and include state-specific rate based goals for carbon dioxide emissions.

From a regulatory perspective, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in construction activities of the New Units which are expected to reduce GHG emission levels significantly once they are completed and dispatched by potentially displacing some of the current coal-fired generation sources. These actions are expected to address many of the rules and regulations discussed herein.

In July 2011, the EPA issued the CSAPR to reduce emissions of sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, thus delaying the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and

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annual or ozone season nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for sulfur dioxide and nitrogen oxide and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the allowances set by the CSAPR.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective.  The rule provides up to four years for generating facilities to meet the standards, and SCE&G and GENCO's evaluation of the rule is ongoing. SCE&G's decision 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 SCE&G's compliance with MATS. On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities. SCE&G and GENCO have received a one year extension (until April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions will allow time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants that will enhance the control of certain MATS-regulated pollutants.

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 no later than September 30, 2015. Once the rule becomes effective, state regulators will modify facility NPDES permits to match more restrictive standards, thus requiring facilities to retrofit with new wastewater treatment technologies. Compliance dates will vary by type of wastewater, and some will be based on a facility's five year permit cycle and thus may range from 2018 to 2023. Based on the proposed rule, Consolidated SCE&G expects that wastewater treatment technology retrofits will be required at Williams and Wateree Stations and may be required at other facilities.

The CWA Section 316(b) Existing Facilities Rule became effective on October 14, 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans to ensure compliance with this rule. In addition, Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones.

On April 17, 2015, the EPA's final rule for CCR was published in the Federal Register and will become effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act. In addition, this rule imposes certain requirements on ash storage ponds at SCE&G's and GENCO's generating facilities. While this rule is still being evaluated, SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds.

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. As of December 31, 2014, 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.

The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The state of South Carolina has similar laws. SCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify 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.

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SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA.  SCE&G anticipates that major remediation activities at all these sites will continue at least through 2017 and will cost an additional $19.2 million, which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.  At March 31, 2015, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $35.2 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.  Prior to January 31, 2015, CGT was a wholly-owned subsidiary of SCANA, and SCE&G's transactions with CGT prior to January 31, 2015 were affiliated transactions. SCE&G's affiliated purchases from CGT totaled approximately $3.4 million and $5.5 million for the three months ended March 31, 2015 and 2014, respectively.  SCE&G's affiliated payables to CGT for transportation services were $3.3 million at December 31, 2014, and SCE&G's affiliated receivables from CGT related to such transportation services were $1.2 million at December 31, 2014.

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 $34.6 million and $53.4 million for the three months ended March 31, 2015 and 2014, respectively.  SCE&G’s payables to SEMI for such purposes were $10.6 million at March 31, 2015 and $12.6 million at December 31, 2014.

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 $70.1 million and $39.2 million for the three months ended March 31, 2015 and 2014, respectively.  SCE&G’s total sales to this affiliate were $69.7 million and $39.0 million for the three months ended March 31, 2015 and 2014, respectively. SCE&G’s receivable from this affiliate was $18.5 million at March 31, 2015 and $27.8 million at December 31, 2014.  SCE&G’s payable to this affiliate was $18.6 million at March 31, 2015 and $27.9 million at December 31, 2014.

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 $73.1 million and $76.2 million for the three months ended March 31, 2015 and 2014, respectively. Consolidated SCE&G's payables to SCANA Services for these services were $48.4 million at March 31, 2015 and $47.3 million at December 31, 2014.

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.

Millions of dollars	External Revenue		Operating Income		Earnings Available to Common Shareholder
Three Months Ended March 31, 2015
Electric Operations	$	630	$	199	n/a
Gas Distribution	142		38		n/a
Adjustments/Eliminations	—		—		$	122
Consolidated Total	$	772	$	237	$	122

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Three Months Ended March 31, 2014
Electric Operations	$	680	$	198	n/a
Gas Distribution	179		41		n/a
Adjustments/Eliminations	—		—		$	123
Consolidated Total	$	859	$	239	$	123

Segment Assets	March 31, 2015		December 31, 2014
Electric Operations	$	10,300	$	10,182
Gas Distribution	731		721
Adjustments/Eliminations	3,103		3,204
Consolidated Total	$	14,134	$	14,107

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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, 2014. 

RESULTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2015

AS COMPARED TO THE CORRESPONDING PERIOD IN 2014

Net Income

Net income for Consolidated SCE&G was as follows:

Millions of dollars	2015		Change		2014
Net income	$	126.3	0.1	%	$	126.2

Net income increased primarily due to higher electric margins (resulting primarily from base rate increases under the BLRA and customer growth, partially offset by milder weather), higher other income and lower operation and maintenance expenses. These increases were partially offset by lower gas margins, higher property taxes, higher depreciation expense, higher interest cost and share dilution, 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 2015:

Declaration Date	Amount	Quarter Ended	Payment Date
February 20, 2015	$70.7 million	March 31, 2015	April 1, 2015
April 30, 2015	$69.7 million	June 30, 2015	July 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:

Millions of dollars	2015		Change		2014
Operating revenues	$	630.3	(7.3	)%	$	679.9
Less: Fuel used in generation	174.5		(18.4	)%	213.8
Purchased power	12.8		(48.8	)%	25.0
Margin	$	443.0	0.4	%	$	441.1

Electric margin increased primarily due to base rate increases under the BLRA ($16.0 million) and residential and commercial customer growth ($4.0 million).  These increases were mostly offset by the effects of weather ($10.4 million), lower industrial margins ($4.1 million), lower residential and commercial average use ($0.7 million) and lower collections under SCE&G’s rate rider for pension costs ($2.6 million). The effects on electric margin of changes in the pension rider are offset by changes in other operating expenses.

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

Classification	2015	Change		2014
Residential	2,092	(2.7	)%	2,151
Commercial	1,715	(2.0	)%	1,750
Industrial	1,468	1.0	%	1,453
Other	140	—	%	140
Total Retail Sales	5,415	(1.4	)%	5,494
Wholesale	246	0.8	%	244
Total Sales	5,661	(1.3	)%	5,738

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

Gas Distribution

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

Millions of dollars	2015		Change		2014
Operating revenues	$	142.3	(20.5	)%	$	178.9
Less: Gas purchased for resale	74.5		(31.8	)%	109.2
Margin	$	67.8	(2.7	)%	$	69.7

Margin decreased $1.0 million due to lower average usage and $1.8 million due to a SCPSC-approved decrease in retail gas base rates under the RSA which became effective in November 2014. These decreases were partially offset by residential and commercial customer growth of $1.6 million.

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

Classification (in thousands)	2015	Change		2014
Residential	7,692	(8.9	)%	8,440
Commercial	4,643	(10.4	)%	5,184
Industrial	4,174	(7.7	)%	4,520
Transportation	1,068	63.3	%	654
Total	17,577	(6.5	)%	18,798

Residential and commercial firm sales volumes decreased due to the effects of weather and lower average use.  These decreases were partially offset by customer growth.  Commercial and industrial interruptible volumes decreased due to curtailments. Transportation volumes increased due to customers shifting to transportation only service.

Other Operating Expenses

Other operating expenses were as follows:

Millions of dollars	2015		Change		2014
Other operation and maintenance	$	138.7	(2.1	)%	$	141.7
Depreciation and amortization	79.9		2.3	%	78.1
Other taxes	54.7		4.6	%	52.3

Other operation and maintenance expenses decreased primarily due to lower labor expenses (including effects of the lower pension rider) of $3.7 million and lower storm expenses of $2.2 million, partially offset byhigher electric operating expenses of $1.7 million, DSM Programs cost amortization of $0.3 million, and other general expenses of $0.7 million. Depreciation and amortization expense increased due to net plant additions.  Other taxes increased primarily due to higher property taxes.

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Other Income (Expense)

Other income (expense) includes the results of certain incidental (non-utility) activities 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 income (expense) increased primarily due to the recognition in the first quarter of 2015, pursuant to SCPSC orders, of $4.4 million of gains realized upon the late 2013 settlement of certain interest rate derivative contracts which were previously recorded as regulatory liabilities.Such gain recognition was offset by downward adjustments to revenues in connection with SCE&G's DSM Programs reflected within electric margin.

Interest Expense

Interest charges increased primarily due to increased borrowings.

Income Taxes

Income taxes for the three months ended March 31, 2015 were approximately the same as income taxes for the three months ended March 31, 2014.

LIQUIDITY AND CAPITAL RESOURCES

Consolidated SCE&G anticipates that its cash obligations will be met through internally generated funds, additional short- and long-term borrowings, 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 three and 12 months ended March 31, 2015 was 3.93 and 3.73, respectively.

SCE&G returned approximately $4 million in equity to its parent company during the three months ended March 31, 2015.

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 TD Bank N.A. These letters of credit expire, subject to renewal, in the fourth quarter of 2019.

At March 31, 2015, Consolidated SCE&G had net available liquidity of approximately $0.8 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 remainder is 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 at a weighted average effective interest rate of 5.7%. Substantially all of the long-term debt bears fixed interest rates or is swapped to fixed. To further preserve liquidity, Consolidated SCE&G rigorously reviews its projected capital expenditures and operating costs and adjusts them where possible without impacting safety, reliability, and core customer service.

SCE&G has obtained FERC authority to issue short-term indebtedness and to assume liabilities as a guarantor(pursuant to Section 204 of the Federal Power Act). SCE&G may issue unsecured promissory notes, commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, banks, and dealers in commercial paper in amounts not to exceed $600 million. GENCO has obtained FERC authority to issue short-term indebtedness not to exceed $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 2015 through 2017, which are subject to continuing review and adjustment, are $940 million in 2015, $1,007 million in 2016, and $899 million in 2017.

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

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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 DER 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.  On March 30, 2015, the SCPSC approved a net energy metering methodology. A hearing before the SCPSC related to specific DER programs proposed by SCE&G is scheduled to begin June 2, 2015.

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 March 31, 2015, SCE&G conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of (a) the effectiveness of the design and operation of its disclosure controls and procedures and (b) any change in its internal control over financial reporting.  Based on this evaluation, the CEO and CFO concluded that, as of March 31, 2015, SCE&G’s disclosure controls and procedures were effective.  There has been no change in SCE&G’s internal control over financial reporting during the quarter ended March 31, 2015, that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.

PART II.  OTHER INFORMATION

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

SCANA:

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

Issuer Purchases of Equity Securities
	(a)	(b)		(c)	(d)
Period	Total number of shares (or units) purchased	Average price paid per share (or unit)		Total number of shares (or units) purchased as part of publicly announced plans or programs	Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs
January 1-31	3,150	$	64.17	3,150
February 1-28	79,958	$	62.27	79,958
March 1-31	138,698	$	55.09	138,698
Total	221,806			221,806	*

*On December 16, 2014 SCANA announced a program to convert from original issue to open market purchase of SCANA common stock for all applicable compensation and dividend reinvestment plans once the sales of certain subsidiaries were completed. These sales were completed in the first quarter of 2015. This program has no stated maximum number of shares that may be purchased and no stated expiration date.

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

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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 Nuclear Development and Other Investor Information sections of the website.  The Nuclear Development section 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 of the website, for an email alert when there is a new posting in the Nuclear Development and Other Investor Information yellow box.

ITEM 6. EXHIBITS

SCANA and SCE&G:

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

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

SIGNATURES

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

SCANA CORPORATION

SOUTH CAROLINA ELECTRIC & GAS COMPANY

(Registrants)

	By:	/s/James E. Swan, IV
Date: May 8, 2015		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)
10.02	X		General Release and Severance Agreement between SCANA and George J. Bullwinkel, Jr. (Filed herewith)
10.03	X		Independent Contractor Agreement between SCANA Services, Inc. and George J. Bullwinkel, Jr. (Filed herewith)
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 and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.02		X	Certification of Principal Executive Officer and 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-10.02

Exhibit 10.02

CONFIDENTIAL GENERAL RELEASE AND SEVERANCE AGREEMENT

BETWEEN

SCANA CORPORATION

and

GEORGE J. BULLWINKEL, JR.

A. INTRODUCTION

This Confidential General Release and Severance Agreement (“Agreement”) is made by and between SCANA Corporation and each of its predecessors, successors, parent entities, subsidiaries, affiliates, related corporations, and assigns (collectively, “SCANA”) and George J. Bullwinkel, Jr. (“Bullwinkel”) (together, the “Parties”). Bullwinkel is employed as the President and Chief Operating Officer of SCANA Communications, Inc., a subsidiary of SCANA Corporation (and included in the definition of “SCANA” above), and serves as a Senior Vice President of SCANA Corporation. The purpose of this Agreement is to state the conditions of Bullwinkel’s separation from SCANA and to resolve any dispute that might exist between Bullwinkel, on the one hand, and SCANA, on the other hand.

B. SCANA’S PROMISES TO BULLWINKEL

In consideration for the promises made by Bullwinkel in this Agreement, SCANA promises to do the following:

(1) SCANA shall provide Bullwinkel severance pay totaling $120,000.00 to be paid in a single lump sum payment on the 15th day after the Effective Date (see Paragraph E(11) to determine the Effective Date). This amount is subject to deductions for state and federal income taxes, FICA, and any other provisions of law to the extent they are applicable.

(2) If, on or before December 31, 2015, the proposed sale of Carolina Gas Transmission Corporation to Dominion Resources, Inc. (“Dominion”) (such transaction, the “CGT Transaction”), closes and becomes effective, SCANA shall provide Bullwinkel a transaction bonus payment totaling $383,000 (the “CGT Transaction Bonus”), subject to the conditions set forth in this Paragraph B(2). The CGT Transaction Bonus shall be paid, if at all, on the latest to occur of the following: (a) the 15th day after the Effective Date; (b) the 15th day after the closing of the CGT Transaction; and (c) March 15, 2015. If the CGT Transaction has not closed and become effective on or before December 31, 2015, or if the definitive agreement between SCANA and Dominion setting forth the terms of the CGT Transaction terminates on or before December 31, 2015, this Paragraph B(2) will be null and void and will have no force and effect as of the close of business on December 31, 2015 (or the date that such definitive agreement terminates, if earlier) and SCANA shall not be obligated to provide and Bullwinkel shall not be entitled to receive the CGT Transaction Bonus. The CGT Transaction Bonus amount is subject to deductions for state and federal income taxes, FICA, and any other provisions of law to the extent they are applicable.

(3) If, on or before December 31, 2015, the proposed sale of SCANA Communications, Inc. (“SCI”) to SCTG, LLC d/b/a Spirit Communications (“Spirit”) (such transaction, the “SCI Transaction”), closes and becomes effective, SCANA shall provide Bullwinkel a transaction bonus payment totaling $117,000 (the “SCI Transaction Bonus”), subject to the conditions set forth in this Paragraph B(3). The SCI Transaction Bonus shall be paid,

2

if at all, on the latest to occur of the following: (a) the 15th day after the Effective Date; (b) the 15th day after the closing of the SCI Transaction; and (c) March 15, 2015. If the SCI Transaction has not closed and become effective on or before December 31, 2015, or if the definitive agreement between SCANA and Spirit setting forth the terms of the SCI Transaction terminates on or before December 31, 2015, this Paragraph B(3) will be null and void and will have no force and effect as of the close of business on December 31, 2015 (or the date that such definitive agreement terminates, if earlier) and SCANA shall not be obligated to provide and Bullwinkel shall not be entitled to receive the SCI Transaction Bonus. The SCI Transaction Bonus amount is subject to deductions for state and federal income taxes, FICA, and any other provisions of law to the extent they are applicable.

(4) SCANA agrees to hold harmless and indemnify Bullwinkel against actual expenses, costs and liabilities reasonably incurred by Bullwinkel in connection with the defense of any pending or threatened action, suit or proceeding to which Bullwinkel is made a party by reason of his good faith actions that were within the scope of his duties as an employee of SCANA.

(5) SCANA agrees that it will not, through its Chief Executive Officer, Executive Vice Presidents, or Senior Vice Presidents, make derogatory or disparaging statements, public or private, through any means, including without limitation oral, written or electronic, about Bullwinkel. A negative statement is defined as any statement, opinion, or remark that tends to injure the reputation of or cause embarrassment to Bullwinkel.

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C. BULLWINKEL’S PROMISES TO SCANA

In exchange for the promises of SCANA contained in this Agreement, Bullwinkel promises to do the following:

(1) Bullwinkel agrees that his employment with SCANA ceased or shall cease, as the case may be, on January 31, 2015, and, as of that date, he ceased or shall cease to be an officer of SCANA Corporation or any of its affiliates. Bullwinkel will receive the employee benefits, if any, to which he may be entitled under SCANA’s employee benefit plans (including, ifapplicable, eligibility to enroll in SCANA’s retiree medical, dental and life insurance plans, eligibility to receive bonus or equity awards under SCANA’s several bonus, equity or other plans, and eligibility for payout of paid time off under SCANA’s Paid Time Off policy) as of the date of his termination of employment, to the extent consistent with applicable law and the terms of the employee benefit plans; except that, in no event will Bullwinkel be entitled to any payments in the nature of severance or termination payments except as specifically provided in this Agreement.

(2) Bullwinkel releases and discharges SCANA and each of its predecessors, successors, parent entities, subsidiaries, affiliates, related corporations, and assigns, and each of their respective owners, shareholders, directors, officers, partners, parent entities, attorneys, employees, successors, assigns, affiliates, subsidiaries, and agents (the “Releasees”) from all legal, equitable, and administrative claims that he may have

4

against any of them that have arisen or may arise up through the Effective Date of this Agreement.

(3) Bullwinkel agrees that this release includes the waiver of any claims arising from his employment and other affiliations with SCANA, including his role as an officer, and the termination of that employment and those other affiliations.

(4) This release also specifically includes, but is not limited to, claims based upon or related to:

(a) The Age Discrimination in Employment Act, as amended,

(b) Title VII of the Civil Rights Act of 1964, as amended,

(c) The Family Medical Leave Act of 1993, as amended,

(d) The Americans with Disabilities Act, as amended,

(e) The South Carolina Human Affairs Law, as amended,

(f) The South Carolina Payment of Wages Law, as amended,

(g)    The Employee Retirement Income Security Act of 1974, as amended,

(h) Actual or alleged violations of any other federal or state laws that prohibit employment discrimination, retaliation, or employment termination in violation of public policy,

(i) Actual or alleged claims of emotional distress, defamation, breach of contract, breach of covenant of good faith and fair dealing,

(j)    Claims for attorneys’ fees, and

5

(k) All other claims arising under any federal, state, or local statutory law, common law, ordinances, regulations or equity.

(5) Bullwinkel waives any right he may have to recover in any proceeding based in whole or in part on claims released by him in this Agreement. For example, Bullwinkel waives any right to monetary recovery or reinstatement if such a claim is successfully brought against any of the Releasees or is settled, whether by the Equal Employment Opportunity Commission (“EEOC”) or any other person or entity, including any state or federal agency. Further, Bullwinkel specifically assigns his right to any such recovery to SCANA.

(6) This Agreement does not prohibit Bullwinkel from filing an administrative charge or claim with the South Carolina Human Affairs Commission (“SCHAC”) or the EEOC or from cooperating in an investigation or proceeding conducted by SCHAC or the EEOC. It does, however, preclude Bullwinkel from receiving any monetary or injunctive award or any other recovery in connection with any such claim, charge or proceeding, regardless of who filed or brought the charge.

(7) Bullwinkel agrees that his general release of claims contained in this Agreement includes any claims that he may have, including claims of which he may not presently be aware. This Agreement does not release any claims that may arise after Bullwinkel signs this Agreement. However, the valuable consideration being offered to Bullwinkel in this Agreement is conditioned on his signing the general release of claims contained

6

in this Agreement within the time frame stated in Paragraph E(10), and not revoking this Agreement before the Effective Date as set forth in Paragraph E(11).

(8) Bullwinkel agrees that he has received information concerning SCANA’s inventions, processes, know-how, trade secrets, employee and dependent personal health information and social security numbers, and/or other proprietary and confidential information during his employment with SCANA. Bullwinkel also agrees that he has received such proprietary and confidential information pertaining to third parties through his employment with SCANA. Bullwinkel now agrees and promises not to divulge any of the above-mentioned proprietary or confidential information of SCANA or third parties. Bullwinkel’s obligations under this Agreement are in addition to, and not in limitation or preemption of, all other obligations of confidentiality that he has to SCANA under general legal or equitable principles.

(9) When requested by SCANA in writing, Bullwinkel agrees to return to SCANA all of SCANA’s property in his use or possession that he has not already returned, including, but not limited to, his SCANA identification card and any other SCANA keys, access cards, or badges, SCANA credit cards, message box, customer and/or employee lists, passwords, access codes and other information necessary to access any computer, communications device or electronic database, and any books, files, documents (paper or electronic) electronic data and media generated, owned, or containing information obtained in any form from SCANA. As part of this commitment, Bullwinkel further agrees to delete any and all electronic data of

7

SCANA from all of his personal computers and electronic communications and storage devices, and to certify that he has completed such deletions.

(10) Bullwinkel acknowledges that the incentives that are provided under the terms of this Agreement represent valuable consideration in excess of other forms of compensation or benefits to which he may be entitled. Bullwinkel agrees that he will not argue that the Agreement, in whole or in part, is not supported by sufficient consideration. Bullwinkel acknowledges and agrees that the releases set forth in this Agreement are essential and material terms of this Agreement and that, without such releases, no agreement would have been reached by the Parties and no payments or benefits under this Agreement would have been provided to him.

(11) Bullwinkel agrees that he will not make derogatory or disparaging statements, public or private, through any means, including without limitation oral, written or electronic, about SCANA or its business, products, policies, practices or services. A negative statement is defined as any statement, opinion, or remark that tends to injure the reputation of or cause embarrassment to SCANA or any other person, entity, or corporation released by this Agreement.

(12) Bullwinkel agrees and covenants not to file any suit, action, or complaint asserting claims arising prior to the Effective Date of this Agreement against any of the Releasees identified in Paragraph C(2), nor, except as required by a subpoena, to assist in any such action, in any court, with regard to any claim, demand, liability or obligation arising out of his employment or other affiliations with SCANA or the

8

termination of that employment or those other affiliations. In the event Bullwinkel receives a subpoena compelling testimony or production of information pertaining to SCANA or any of the Releasees, he shall promptly notify the Senior Vice President of Administration of SCANA Corporation in writing of the existence of the subpoena in order that SCANA, or the appropriate Releasee, may seek withdrawal, modification, or a protective order relating to the subpoena. He further represents that no claims, complaints, charges, or other proceedings are pending in any court, administrative agency, commission or other forum relating directly or indirectly to his employment by SCANA.

(13) Upon request by SCANA, Bullwinkel agrees to provide information to SCANA and, if necessary, testimony on SCANA’s behalf, in connection with administrative charges, administrative audits, lawsuits, and other similar legal proceedings to the extent they relate to matters within Bullwinkel’s area of responsibility during his service to SCANA.

D. MISCELLANEOUS TERMS AGREED TO BY THE PARTIES

In exchange for the promises made by and to Bullwinkel and SCANA, they mutually agree to the following terms:

(1) Either party may enforce this Agreement in court if the other party breaches it.

(2) This Agreement may be used in a subsequent proceeding to enforce its terms.

(3) The language of all parts of this Agreement shall be construed as a whole and according to its fair meaning, and not strictly for or against either party. It is

9

expressly understood and agreed that any rule requiring construction of this Agreement against the drafter will not apply in any dispute involving the Agreement.

(4) SCANA does not admit and expressly denies violating any state, federal, or local laws by entering into this Agreement. Bullwinkel acknowledges that this Agreement and the consideration offered in it shall not be construed as an admission of any wrongdoing or liability on the part of SCANA.

(5) This Agreement contains the entire and only Agreement between Bullwinkel and SCANA on the subject matter of this Agreement. Both Parties waive any oral or written promises or assurances on the subject matter of this Agreement that are not contained in, or expressly incorporated into, this Agreement. Notwithstanding the foregoing, Bullwinkel will be entitled to all compensation and benefits to which he is entitled pursuant to the terms of any SCANA PTO policies or any SCANA employee benefit plans in which he was fully vested while an employee of SCANA.

(6) This Agreement shall be binding upon and be for the benefit of the Parties and their respective heirs, legal representatives, successors, and assigns.

(7) This Agreement shall be governed by and construed in accordance with the law of the State of South Carolina, without regard to any conflicts of law principles.

(8) This Agreement was drafted with the intent to comply with the short-term deferral exemption from Section 409A of the Internal Revenue Code of 1986, as amended, and the provisions of the Agreement shall be interpreted in a manner consistent with that intent. However, Bullwinkel acknowledges and agrees that no person connected

10

with SCANA or the Releasees has made or hereby makes any representations, commitments, or guarantees that any specific tax treatment (including, but not limited to, federal, state and local tax treatment) will be applicable with respect to the amounts owed or paid under this Agreement. Bullwinkel is advised to consult with his own tax advisers to ensure any particular tax result under this Agreement and may not rely on SCANA, the Releasees, nor their respective officers, directors, agents or employees for tax advice.

(9) To accept the Agreement, and payments under this Agreement, Bullwinkel must sign the Agreement and return it (via U.S. Mail, courier, or hand-delivery) to Martin K. Phalen, Senior Vice President of Administration, SCANA Corporation, 100 SCANA Parkway, Mail Code D-311, Cayce, South Carolina 29033-3712, within the time frame set forth in Paragraph E(10). The Agreement will become effective upon Bullwinkel signing the Agreement and returning it to Phalen as set forth in this paragraph and not revoking this Agreement before the Effective Date as set forth in Paragraph E(11).

(10) Bullwinkel expressly acknowledges that a breach of any of the terms and conditions contained in this Agreement will cause SCANA irreparable and continuing harm for which there is no adequate remedy at law and SCANA is therefore entitled to seek injunctive relief and specific performance without the requirement of posting a bond. SCANA’s right to seek injunctive relief and specific performance shall in no way limit its right to seek any other legal remedies or other relief available to it.

11

(11) If any terms or provisions of this Agreement are found null, void or inoperative, for any reason, the remaining provisions will remain in full force and effect. However, if the releases set forth in this Agreement are held to be illegal or unenforceable, Bullwinkel agrees to execute a valid release and waiver in favor of SCANA and the Releasees.

E.BULLWINKEL’S ASSURANCES TO SCANA

This Agreement is a legal document with legal consequences. SCANA wants to be certain that Bullwinkel fully understands the legal effect of signing this Agreement. Bullwinkel, therefore, makes the following assurances:

(1)    I have carefully read the complete Agreement.

(2)    The Agreement is written in language that I understand.

(3)    I understand all of the provisions of this Agreement.

(4)    I understand that this Agreement is a waiver of any and all claims I may have against SCANA and all the Releasees.

(5)    I also understand that this Agreement is a waiver of any and all claims of age discrimination I have under the Age Discrimination in Employment Act.

(6)    I willingly waive any and all claims, known and unknown, in exchange for the promises of SCANA in this Agreement. I understand, however, that I am not currently releasing any claims that arise after I sign this Agreement.

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(7)    I want to enter this Agreement. I recognize that the Agreement is financially beneficial to me. I further acknowledge that the benefits I receive under this Agreement are benefits to which I am not already entitled.

(8)    I enter this Agreement freely and voluntarily. I am under no coercion or duress whatsoever in considering or agreeing to the provisions of this Agreement.

(9)    I understand that this Agreement is a contract. As such, I understand that either party may enforce it.

(10)    By signing this Agreement, I acknowledge that I have been given a period of 45 days to decide whether to enter into this Agreement. This 45 day period has provided me with sufficient time to consider my options and to seek the advice of legal counsel, tax or financial advisors, and anyone else whose advice I value. I understand that if I execute this Agreement prior to the end of the 45 day period SCANA gave me to consider the Agreement, such early execution is a knowing and voluntary waiver of any right to consider this Agreement for at least 45 days and was due to my belief that I had ample time to consider the Agreement and review it with an attorney. By signing this Agreement, I also acknowledge that I have been informed in writing of the following information:

a.    The group of employees and business units covered by this severance program;

13

b.    The job titles and ages of affected individuals eligible or selected for the severance program and the job titles and ages of all individuals in the covered group who were not affected by this program as of the Termination Date; and

c.    The eligibility requirements and time limits of this severance program.

(11)    After signing this Agreement, I have a period of seven days to revoke it. I can revoke this Agreement by notifying Martin Phalen at SCANA in writing of my decision to revoke the Agreement within the seven day period. Such notice must be delivered by hand to the address set forth in Paragraph D(9) or by electronic mail (MPhalen@SCANA.com). In fact, this Agreement is not effective until the eighth day after it is signed (the “Effective Date”).

(12) SCANA hereby advises me in writing to consult with an attorney prior to signing this Agreement.

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IN WITNESS THEREOF, the Parties have executed this Agreement on 30day of

January , 2015.

/s/George J. Bullwinkel, Jr.    ____________1/30/15__________________

George J. Bullwinkel, Jr. (Date)

I     /s/Veronica June Pritchard, attest that the above-named individual signed this

Agreement and Release on the 30th     of     January , 2015.

Notary Public for the State of South Carolina

My Commission Expires: MY COMMISSION EXPIRES 03-147-2018

For SCANA:

/s/Martin K. Phalen _____________2/3/15_________________

Martin K. Phalen                 (Date)

Senior Vice President of Administration,

SCANA Corporation

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EX-10.03

Exhibit 10.03

INDEPENDENT CONTRACTOR AGREEMENT

THIS INDEPENDENT CONTRACTOR AGREEMENT (“Agreement”) is effective as of February 1, 2015 (the “Effective Date”), by and between SCANA Services, Inc.(“SCANA”), a subsidiary of SCANA Corporation, and George J. Bullwinkel, Jr. (“Contractor”), pursuant to which Contractor will provide services, as set forth below, to assist SCANA under the terms and conditions and for the consideration set forth below.

RECITALS

WHEREAS, Contractor previously served as the President and Chief Operating Officer of SCANA Communications, Inc., a subsidiary of SCANA Corporation; and Senior Vice President of SCANA Corporation and its subsidiary SCANA Services, Inc., prior to his retirement, which became effective on February 1, 2015 (the “Retirement Date”).

WHEREAS, SCANA desires to engage Contractor post-retirement as an independent contractor and not as an employee of SCANA, SCANA Corporation or any of their affiliates, for the purpose of providing advice and assistance on issues that may arise concerning the sales of SCANA Communications, Inc., and Carolina Gas Transmission Corporation.

WHEREAS, SCANAdoes not seek and does not assert any control over the day-to-day activities of Contractor in performing the services necessary to accomplish the objectives set forth in this Agreement. Further, Contractor will be solely responsible for scheduling his work hours to timely accomplish the objectives described in this Agreement, subject to the limitations described in this Agreement. SCANAis concerned only with the results and not the manner in which Contractor goes about his work.

WHEREAS, Contractor possess the requisite skills, training, and expertise to perform the services called for under this Agreement, and Contractor wishes to perform services based on the terms and conditions in this Agreement.

WHEREAS, Contractor understands that he will be performing services under this Agreement as an independent contractor and not as an employee of SCANAand, therefore, will be solely responsible for all federal and state tax obligations imposed with respect to payments received from SCANA. Further, SCANAwill not pay any Federal Insurance Contributions Act (“FICA”) taxes or Federal Unemployment Tax Act (“FUTA”) taxes, will not withhold or pay any income tax withholding or FICA taxes on Contractor’s behalf, and will not cover Contractor for workers’ compensation purposes. Contractor is a fully independent contractor offering services to SCANAand the general public and, therefore, is able to perform work for companies other than SCANA.

WHEREAS, Contractor agrees to release and indemnify SCANAof any and all liability for any claim for workers’ compensation benefits, any claim for compensation or any tax liabilities or consequences which could arise out of Contractor’s failure to pay compensation or withhold taxes from any employee’s pay in accordance with state or federal law.

THEREFORE, in consideration of the mutual promises set forth in this Agreement, SCANAand Contractor agree as follows:

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ARTICLE I

TERMS AND TERMINATION

1.1 Term of Agreement

This Agreement will take effect on the Effective Date, and continue in full force and effect through December 31, 2015 (the “Contract Period”), unless terminated on an earlier date in accordance with Section 1.2 of this Agreement.

1.2 Termination of Agreement

SCANA may terminate this Agreement immediately if it determines that Contractor lacks the skills necessary to accomplish the objectives contracted for by SCANA, Contractor’s work fails to meet the expectations of SCANA, or Contractor breaches any term of this Agreement. Notwithstanding the foregoing, this Agreement will terminate pursuant to its own terms in accordance with Section 1.1 of this Agreement.

ARTICLE II

STATUS AS INDEPENDENT CONTRACTOR

2.1 Duties and Responsibilities of Contractor

During the Contract Period, in addition to performing any other consulting services that SCANA and Contractor may from time to time agree upon, and subject to the limitations set forth in this Agreement, Contractor shall provide advice and assistance on issues that may arise concerning the sales of SCANA Communications, Inc., and Carolina Gas Transmission Corporation. Contractor shall carry out his responsibilities and perform the services pursuant to this Agreement in a faithful and diligent manner.

SCANA and Contractor do not anticipate or intend for Contractor’s Services to exceed 20% of the average level of services provided by Contractor to SCANA over the 36-month period preceding the Retirement Date, and it is intended that Contractor’s change in status from President of SCANA Communications, Inc. and Senior Vice President of SCANA Corporation to Contractor will be a “separation from service” within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), and the regulations thereunder. Further, in no event shall Contractor provide services at a level that would invalidate Contractor’s “separation from service” from SCANA Communications, Inc. and SCANA Corporation for purposes of Section 409A of the Code.

Nothing in this Agreement will preclude Contractor from engaging in other business ventures or services so long as Contractor is not otherwise in breach of this Agreement or any other agreement Contractor may have with SCANA, and Contractor will have complete control over the manner and means by which Contractor’s services are performed under this Agreement. SCANA acknowledges that Contractor has or may have other clients.

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2.2 Consideration

As full consideration for Contractor’s services, SCANAshall pay Contractor a total of $230,000 (the “Service Fees”), to be paid monthly in arrears; provided that payment of the first five monthly Service Fees shall be paid with the Service Fees of the sixth month (i.e., the first six months of Service Fees shall be paid in one installment as soon as practicable after the six month anniversary of the Effective Date).

2.3 Status of Contractor as Independent Contractor

Contractor understands that for all purposes under this Agreement, he will operate as an independent contractor. Accordingly, the following provisions will apply:

2.3.1 Contractor shall choose the time, location, and manner in which all services are performed, according to his own judgment, as long as the objectives set forth in this Agreement are met in a satisfactory manner. SCANAdoes not have the right to control the details and means by which Contractor’s services are rendered. SCANAonly seeks the benefits of the results of Contractor’s efforts and, except as otherwise provided in this Agreement, Contractor assumes and retains discretion for the methods, details, means, techniques and procedures to be utilized in the performance of Contractor’s services covered by this Agreement. In particular, SCANAhas no right or authority to direct or control Contractor regarding the number of hours worked, place of work, or dates of work (except as set forth in Section 2.1 of this Agreement).

2.3.2 Contractor expressly agrees that he shall not be considered an employee of SCANAfor any purpose associated with the performance under this Agreement. Contractor shall sign and submit the form attached as ADDENDUM I prior to beginning work covered by this Agreement. Both SCANAand Contractor acknowledge that, without this Agreement, no relationship or other requirements exists between them; and that pursuant to this Agreement, Contractor is an independent contractor. None of the benefits that SCANAprovides to its employees will be available to Contractor (or his employees, if any). This provision in no way voids or adversely affects Contractor’s rights to benefits he earned and to which he was fully vested while he was an employee of any affiliate of SCANA Corporation prior to the Effective Date. In addition, if a court, the Internal Revenue Service, or any other enforcement authority or agency determines that Contractor should be reclassified as an employee of SCANA or one of its affiliates, Contractor specifically agrees and understands that such determination will not have a retroactive effect for purposes of eligibility to participate in any employee benefit plan of SCANA, even if such determination is applicable to prior years.

2.3.3 For all tax purposes, including but not limited to, FICA; the Social Security Act; the Immigration Reform and Control Act; FUTA; income tax withholdings; and any and all other federal, state, or local laws, rules, and regulations, Contractor

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and each of his employees, if any, will be treated as independent contractors and not employees of SCANA.

2.3.4 Contractor acknowledges and agrees that he shall be responsible for filing all tax returns, tax declarations, tax schedules, and for the payment of all taxes required when due with respect to any and all compensation derived from the services performed under this Agreement.

2.3.5 Contractor agrees to indemnify and hold SCANA (including its officers, managers, employees, and agents) harmless against any and all claims, losses, liabilities, damages, and expenses arising out of, or as a result of, any work performed by Contractor while acting pursuant to this Agreement, except for any and all claims, losses, liabilities, damages and expenses directly arising out of the negligence of SCANA, up to the limits of any insurance coverage. SCANA agrees to indemnify and hold Contractor harmless against any and all claims, losses, liabilities, damages and expenses directly arising out of the negligence (including ordinary or gross negligence) of SCANA or out of any reckless or intentional acts of SCANA.

2.4 Training by SCANA

SCANA acknowledges Contractor’s existing training, skills, and experience as related to the objectives in this Agreement to be completed. Contractor represents that his employees, if any, are fully trained to perform the services contracted for and that they are not in need of any training by SCANA. Therefore, SCANA will not provide Contractor or his employees, if any, with any training related to the objectives in this Agreement.

2.5 Contractor’s Assistants

Contractor shall have the right to engage assistants in completing the duties set forth in this Agreement as he deems appropriate. Contractor shall be responsible for paying any and all compensation and any applicable employment taxes that might be owed on account of any such employees or assistants, and Contractor shall indemnify and hold SCANA harmless against any such liabilities. Contractor agrees to provide his employees and assistants with workers’ compensation coverage.

2.6 Contractor’s Access to SCANA Employees

SCANA acknowledges it may be beneficial for Contractor to interact with certain SCANA employees during the performance of this Agreement. Therefore, SCANA agrees to make certain employees available to Contractor only for advisory and administrative purposes. Any individual employed by SCANA will not be considered an “assistant” of Contractor as described in Section 2.5 of this Agreement, nor will Contractor have any input into any personnel action of a SCANA employee advising him or providing administrative support to him in relation to this Agreement.

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2.7 Tools and Materials and Equipment

Contractor must furnish all tools, all materials, and all other equipment necessary to perform the services contracted for under this Agreement.

2.8 No Representations/Commitments

Contractor will not make any representation, warranty, agreement or commitment on behalf of SCANA without the advance written authorization of SCANA.

2.9 Confidentiality

Contractor acknowledges that, in order to successfully perform the services described in this Agreement, it is necessary for SCANA to entrust Contractor with certain valuable proprietary information and knowledge of certain modes of business operation, and particular information concerning the affairs, practices, and other information concerning SCANA (“Confidential Information”). Contractor acknowledges that he has acquired or will acquire Confidential Information in the course of or incident to performing services under this Agreement and Contractor agrees that neither he nor his employees or any third person or firm engaged by Contractor will directly or indirectly, at any time, during or after the term of this Agreement use or cause to be used any such Confidential Information in connection with any activity or business other than the business contemplated by this Agreement for SCANA. Contractor (on behalf of himself, his employees, and any person or firm he engages) also agrees that Contractor and his employees will not disclose such Confidential Information to any other party unless such disclosure has been authorized in writing by SCANA or SCANA Corporation, except (i) as may be required by any applicable law or by order of a court of competent jurisdiction or a government body, (ii) to the extent that such information has been made public, or (iii) to the extent lawfully received from a third party without confidentiality or use restrictions. Upon the termination of this Agreement for any reason, Contractor and its employees and any person or firm engaged by Contractor agree that each immediately will return to SCANA, any and all Confidential Information and all other materials (including computers, fax machines, printers, cell phone and other equipment) or documents, including without limitation mailing lists, rolodexes, computer print-outs, and computer disks and tapes belonging to SCANA which contain information pertaining to SCANA’s business, methods, customers, potential customers or employees unless SCANA agrees in writing to Contractor’s retention thereof.

ARTICLE 3

GENERAL PROVISIONS

3.1 Governed by South Carolina Law

This Agreement will be governed by the laws of the State of South Carolina and the United States.

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3.2 Notices

Any notice required or permitted under the Agreement will be in writing and sent to the other party by first class mail at the address below or to such other address as a party to this Agreement may specify in writing.

SCANAContractor

Martin K. Phalen                George J. Bullwinkel, Jr.

Mail Code D311                [ ]

100 SCANA Parkway                [ ]

Cayce, SC 29201                

[ ]

3.3 Entire Agreement

This Agreement, including any Addendums, constitutes the entire agreement between the parties on the subject matter of the Agreement and supersedes and replaces any and all previous agreements on that subject matter, either oral or written. Notwithstanding the foregoing, Contractor will be entitled to all compensation or benefits for which he is entitled pursuant to the terms of any SCANA benefit plans in which he was fully vested while an employee of SCANA. No modifications, amendments, or changes to this Agreement will be binding on the parties unless and until the parties have approved the modifications in writing.

3.4 Severability/Blue Pencil

If any provision of this Agreement is found, held, or deemed to be void, unlawful, or unenforceable for any reason, then such invalid or unenforceable section will be removed and not affect the other parts of this Agreement, which parts will remain in full force and effect. If a court should determine that any portion of this Agreement is overbroad or unreasonable, such provision will be given effect to the maximum extent possible by narrowing or enforcing in part that aspect of the provision found to be overbroad or unreasonable.

3.5 Waivers Not Continuing

No breach of any provision of this Agreement can be waived unless in writing. Waiver of any breach of any provision will not be deemed to be a waiver of any further breach of the same or any other provision of this Agreement.

3.6 Assignability

SCANA may transfer or assign this Agreement (in whole or in part) to any subsidiary or affiliate of SCANA or to any entity with which SCANA may be merged or consolidated, or which may acquire substantially all of the existing business of SCANA. This Agreement will inure to the benefit of and will be binding upon the successors or

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permitted assigns of SCANA. If this Agreement is assigned in accordance with the foregoing provisions, all references in this Agreement to SCANA will likewise be deemed to be references to the successor or assignee. Contractor may not transfer, assign, or otherwise convey this Agreement or any part of Contractor’s interest in this Agreement.

3.7 Laws

Contractor agrees to be responsible for compliance with all federal, state and local laws, rules and regulations applicable to its performance of this contract.

3.8 Use of SCANA’s Name or Logo

Contractor shall not use SCANA’s name or logo as a reference or for any other purpose without prior consent from an authorized representative of SCANA.

3.9 Reports

Contractorshall furnish SCANA periodic reports of the progress of the work, if requested by SCANA. Such reports shall be made as frequently as requested and in the form prescribed by SCANA.

3.10 Work for Hire

Contractor agrees that all copyrightable material, notes, records, drawings, designs, inventions, improvements, developments, discoveries and trade secrets conceived, discovered, developed or reduced to practice by Contractor, solely or in collaboration with others, during the Contract Period that substantially relate to the business of SCANA (and/or its products and services) that Contractor may be directed to undertake, investigate or experiment with or that Contractor may become associated with in work, investigation or experimentation in SCANA’s line of business in performing Contractor Services under this Agreement (collectively, “Inventions”), are the sole property of SCANA. Contractor also agrees to assign (or cause to be assigned) and hereby assigns fully to SCANA all Inventions and any copyrights, patents, mask work rights or other intellectual property rights relating to all Inventions at the expense of SCANA. Contractor agrees to assist SCANA, or its designee, at SCANA’s expense, in every proper way to secure SCANA’s rights in Inventions and any copyrights, patents, mask work rights or other intellectual property rights relating to all Inventions in any and all countries, including the disclosure to SCANA of all pertinent information and data with respect to all Inventions, the execution of all applications, specifications, oaths, assignments and all other instruments that SCANA may deem necessary in order to apply for and obtain such rights and in order to assign and convey to SCANA, its successors, assigns and nominees the sole and exclusive right, title and interest in and to all Inventions, and any copyrights, patents, mask work rights or other intellectual property rights relating to all Inventions. Contractor also agrees that Contractor’s obligation to execute or cause to be executed any such instrument or papers shall continue after the termination of the Contract Period.

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3.11 Additional Terms and Conditions

Contractor agrees to abide by the attached General Terms and Conditions For Purchases That Include Services to the extent they are consistent with this Agreement. In the case of an inconsistency the terms of this Agreement will control.

3.12 Modification

This Agreement may be modified at any time by mutual written agreement of the parties.

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IN WITNESS WHEREOF, the parties execute this Independent Contractor Agreement as of February 1, 2015.

SCANA SERVICES, INC.

By:    /s/Martin K. Phalen            

Title:     Senior Vice President – SCANA Admin. 2/3/15

CONTRACTOR

/s/George J. Bullwinkel, Jr.            

George J. Bullwinkel, Jr.

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ADDENDUM I

ACKNOWLEDGMENT AND AFFIRMATION BY EMPLOYEE

OR CONTRACTOR OF INDEPENDENT CONTRACTOR

In conformance with Section 2.3.2 of this Agreement, George J. Bullwinkel, Jr., in his individual capacity, specifically waives entitlement to any benefits SCANA provides to its employees. This provision in no way voids or adversely affects his rights to benefits he earned and to which he was fully vested while he was an employee of SCANA or one of its affiliates prior to the date of this Agreement. In addition, if a court, the Internal Revenue Service, or any other enforcement authority or agency will determine that Bullwinkel should be reclassified as an employee of SCANA or one of its affiliates, Bullwinkel specifically agrees and understands that such determination will not have a retroactive effect for purposes of eligibility to participate in any employee benefit plan of SCANA, even if such determination is applicable to prior years.

/s/George J. Bullwinkel, Jr.

George J. Bullwinkel, Jr.

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EX-12.01

Exhibit 12.01

COMPUTATION OF RATIOS

March 31, 2015

RATIO OF EARNINGS TO FIXED CHARGES

SCANA:	Three Months Ended March 31, 2015		Twelve Months Ended March 31, 2015			Years ended December 31,
Dollars in Millions						2014			2013			2012			2011			2010
Fixed Charges as defined:
Interest on debt		$79.5		$319.8			$318.2			$305.9			$301.3			$287.0			$270.4
Amortization of debt premium, discount and expense (net)	1.3		9.6			9.7			5.3			4.9			4.8			5.1
Interest component on rentals	0.8		4.0			4.1			4.9			4.9			5.2			4.6
Preference security dividend requirement of consolidated subsidiary	-		-			-			-			-			-			0.0
Total Fixed Charges (A)		$81.6		$333.4			$332.0			$316.1			$311.1			$297.0			$280.1
Earnings as defined:
Pretax income from continuing operations		$627.4	$1,136.8				$786.0			$693.8			$601.6			$555.6			$535.4
Total fixed charges above	81.6		333.4			332.0			316.1			311.1			297.0			280.1
Pretax equity in (earnings) losses of investees	-		(0.3		)	(1.4		)	(3.2		)	(3.3		)	(2.9		)	(1.1		)
Cash distributions from equity investees	1.0		4.5			7.4			9.6			3.3			3.6			4.8
Preference security dividend requirement from above	-		-			-			-			-			-			0.0
Total Earnings (B)	$710.0		$1,474.4			$1,124.0				$1016.3			$912.7			$853.3			$819.2
Ratio of Earnings to Fixed Charges (B/A)	8.70		4.42			3.39			3.22			2.93			2.87			2.92

SCE&G:	Three Months Ended March 31, 2015		Twelve Months Ended March 31, 2015		Years ended December 31,
Dollars in Millions					2014		2013		2012		2011		2010
Fixed Charges as defined:
Interest on debt		$61.3		$241.0		$237.6		$226.4		$217.4		$207.8		$192.4
Amortization of debt premium, discount and expense (net)	1.1		4.4		4.4		4.2		3.9		3.9		4.0
Interest component on rentals	1.0		4.1		4.0		4.5		3.2		3.6		3.1
Total Fixed Charges (A)		$63.4		$249.5		$246.0		$235.1		$224.5		$215.3		$199.5
Earnings as defined:
Pretax income from continuing operations		$184.2		$675.2		$676.0		$579.7		$509.5		$456.5		$433.6
Total fixed charges above	63.4		249.5		246.0		235.1		224.5		215.3		199.5
Pretax equity in (earnings) losses of investees	1.7		6.3		5.3		3.5		3.8		2.3		2.1
Total Earnings (B)		$249.3		$931.0		$927.3		$818.3		$737.8		$674.1		$635.2
Ratio of Earnings to Fixed Charges (B/A)	3.93		3.73		3.77		3.48		3.29		3.13		3.18

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Kevin B. Marsh, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 8, 2015
	/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: May 8, 2015
	/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: May 8, 2015
	/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: May 8, 2015
	/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 March 31, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: May 8, 2015
/s/Kevin B. Marsh	/s/Jimmy E. Addison
Kevin B. Marsh	Jimmy E. Addison
Chairman of the Board, President, Chief Executive Officer	Executive Vice President and Chief Financial Officer
and Chief Operating Officer

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 South Carolina Electric & Gas Company (the “Company”) on Form 10-Q for the quarter ended March 31, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we 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.

May 8, 2015
/s/Kevin B. Marsh	/s/Jimmy E. Addison
Kevin B. Marsh	Jimmy E. Addison
Chairman of the Board and Chief Executive Officer	Executive Vice President and Chief Financial Officer

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2015 MMBTU	Dec. 31, 2014 MMBTU
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	60,113,497	55,733,059
Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	10,140,000	6,840,000
Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	5,633,000	7,951,000
Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	44,340,497	40,942,059
Commodity Contract
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	19,301,964	18,237,720
Commodity Contract | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	10,140,000	6,840,000
Commodity Contract | Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	5,633,000	7,951,000
Commodity Contract | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	3,528,964	3,446,720
Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	40,811,533	37,495,339
Energy Related Derivative [Member] | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0	0
Energy Related Derivative [Member] | Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0	0
Energy Related Derivative [Member] | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	40,811,533	37,495,339
Energy Related Derivative [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	3,148,404	933,893
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Interest Rate Derivatives [Abstract]
Derivative, Notional Amount	1,300.0	1,100.0
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Interest Rate Derivatives [Abstract]
Derivative, Notional Amount	124.4	124.4
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Interest Rate Derivatives [Abstract]
Derivative, Notional Amount	1,300.0	1,100.0
SCEG | Cash Flow Hedging [Member] | Interest Rate Swap [Member]
Interest Rate Derivatives [Abstract]
Derivative, Notional Amount	36.4	36.4

XML

SEGMENT OF BUSINESS INFORMATION (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Segment Reporting Information [Line Items]
Gain (Loss) on Disposition of Nonregulated Business, Net of Transaction Costs	$ 202
Electric Domestic Regulated Revenue	629	678
Intersegment Revenue	0	0
Operating Income	586	350
Regulated Operating Revenue, Gas	369	458
Regulated and Unregulated Operating Revenue	1,389	1,590
Income Available to Common Shareholders	400	193
Segment Assets	16,406		16,852
Electric Operations
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	629	678
Intersegment Revenue	0	2
Operating Income	199	198
Segment Assets	10,300		10,182
Gas Distribution
Segment Reporting Information [Line Items]
Intersegment Revenue	0	0
Operating Income	96	97
Regulated and Unregulated Operating Revenue	368	455
Segment Assets	2,504		2,487
Retail Gas Marketing
Segment Reporting Information [Line Items]
Intersegment Revenue	0	0
Regulated and Unregulated Operating Revenue	204	220
Income Available to Common Shareholders	27	22
Segment Assets	155		140
Energy Marketing [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue	35	53
Regulated and Unregulated Operating Revenue	187	234
Income Available to Common Shareholders	6	7
Segment Assets	128		150
All Other [member]
Segment Reporting Information [Line Items]
Intersegment Revenue	114	110
Operating Income	238	8
Regulated and Unregulated Operating Revenue	4	9
Income Available to Common Shareholders	207	4
Segment Assets	1,494		1,474
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Intersegment Revenue	(149)	(165)
Operating Income	53	47
Regulated and Unregulated Operating Revenue	(3)	(6)
Income Available to Common Shareholders	160	160
Segment Assets	1,825		2,419
SCEG
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	630	680
Operating Income	237	239
Regulated Operating Revenue, Gas	142	179
Net Income (Loss) Attributable to Parent	122	123
Segment Assets	14,134		14,107
Regulated Operating Revenue	772	859
SCEG | Electric Operations
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	630	680
Operating Income	199	198
Segment Assets	10,300		10,182
SCEG | Gas Distribution
Segment Reporting Information [Line Items]
Operating Income	38	41
Regulated Operating Revenue, Gas	142	179
Segment Assets	731		721
SCEG | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Operating Income	0	0
Net Income (Loss) Attributable to Parent	122	123
Segment Assets	3,103		3,204
Regulated Operating Revenue	$ 0	$ 0

XML

EMPLOYEE BENEFIT PLANS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension and Other Postretirement Benefit Plans
Pension Contributions	No	No
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	5.8	5.0
Interest cost	9.5	10.2
Expected return on assets	(15.5)	(16.8)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	1.0	1.0
Defined Benefit Plan, Actuarial Net (Gains) Losses	3.5	1.3
Defined Benefit Plan, Net Periodic Benefit Cost	4.3	0.7
Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.4	1.2
Interest cost	2.9	3.1
Expected return on assets	0	0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.1	0.1
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.6	0.1
Defined Benefit Plan, Net Periodic Benefit Cost	5.0	4.5
SCEG
Pension and Other Postretirement Benefit Plans
Pension Contributions	No	No
SCEG | Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	4.6	4.0
Interest cost	8.0	8.6
Expected return on assets	13.0	14.2
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.8	0.9
Defined Benefit Plan, Actuarial Net (Gains) Losses	(3.0)	(1.1)
Defined Benefit Plan, Net Periodic Benefit Cost	3.4	0.4
SCEG | Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.1	1.0
Interest cost	2.3	2.4
Expected return on assets	0	0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.1	0.1
Defined Benefit Plan, Actuarial Net (Gains) Losses	(0.4)	(0.1)
Defined Benefit Plan, Net Periodic Benefit Cost	3.9	3.6
Pension Costs [Member] | SCEG
Components of Net Periodic Benefit Cost
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	14				$ 63
Regulatory Noncurrent Asset, Amortization Period	12		14	30

XML

RATE AND OTHER REGULATORY MATTERS (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended		9 Months Ended	12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2014	Dec. 31, 2015	Mar. 31, 2013	Dec. 31, 2012
Regulatory Assets
Regulatory Liabilities	$ 829		$ 814
Public Utilities Base Fuel under Collected Balance Recovery Period	12
Regulatory Assets, Noncurrent	1,890.0		1,823.0
SCEG
Regulatory Assets
Regulatory Asset Recovery Assessments		12
Public Utilities, Rate Calculation Basis	12-month rolling average
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%
Regulatory Liabilities	621		610
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates	2.5
Carrying costs on deferred income tax assets	1.9	1.2
Derivative, Gain on Derivative			17.8
Storm Damage Reserve Cost Applied			5.0
Demand Side Management Program Costs, Noncurrent	32.0	15.4					16.9
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs	100
Public Utilities Base Fuel under Collected Balance Recovery Period	12
Regulatory Assets, Noncurrent	1,817.0		1,745.0
Demand side management recovery period	5
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
Amounts Recovered Through Electric Rates to offset Nuclear Related Outage Costs	17.2
Public Utilities, Authorized Allowable Return on Common Equity, Percentage	11.00%
PSNC Energy [Member]
Regulatory Assets
Public Utilities, Rate Calculation Basis		12
Regulatory Assets, Noncurrent	1.0
Other Regulatory Liability [Member]
Regulatory Assets
Regulatory Liabilities	0		1
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory Liabilities	712		703
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	510		505
Deferred Income Tax Charges [Member]
Regulatory Assets
Regulatory Liabilities	22		22
Deferred Income Tax Charges [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	16		17
Storm damage reserve [Member]
Regulatory Assets
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM			5.0
Regulatory Liabilities	6		6
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 Assets
Regulatory Liabilities	6		6
Planned major maintenance [Member]
Regulatory Assets
Regulatory Liabilities	7		0
Planned major maintenance [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	7		0
Amounts Recovered through Electric Rates to offset Turbine Expense	18.4
Deferred gains on interest rate derivatives [Member]
Regulatory Assets
Regulatory Liabilities	82		82
Deferred gains on interest rate derivatives [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	82		82
Franchise agreement Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	25.0		26.0
Franchise agreement Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	25.0		26.0
Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	549.0		453.0
Deferred Losses On Interest Rate Derivatives [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	549.0		453.0
Deferred Pollution Control Cost [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	35.0		36.0
Deferred Pollution Control Cost [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	35.0		36.0
Regulatory Clause Revenues, under-recovered [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	4.0		20.0
Regulatory Clause Revenues, under-recovered [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	4.0		20.0
Planned major maintenance [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	0		2.0
Planned major maintenance [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	0		2.0
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	90
Regulatory Assets, Noncurrent	370.0		366.0
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	350.0		347.0
unrecovered plant [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	132.0		137.0
unrecovered plant [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	132.0		137.0
Demand Side Management programs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	58.0		56.0
Demand Side Management programs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	58.0		56.0
Carrying cost on nuclear construction [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	11.0		9.0
Carrying cost on nuclear construction [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	11.0		9.0
Pipeline integerity management costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	10.0		9.0
Deferred Income Tax Charges [Member]
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	70
Regulatory Assets, Noncurrent	282.0		284.0
Deferred Income Tax Charges [Member] | SCEG
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	70
Regulatory Assets, Noncurrent	276.0		278.0
Environmental Restoration Costs [Member]
Regulatory Assets
MPG enviromental remediatio	25
Regulatory Assets, Noncurrent	40.0		40.0
Environmental Restoration Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	35.0		36.0
Pension Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	337.0		350.0
Pension Costs [Member] | SCEG
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	12		14	30
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	14							63
Regulatory Assets, Noncurrent	305.0		310.0
Other Regulatory Assets [Member]
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	30				30
Regulatory Assets, Noncurrent	37.0		35.0
Other Regulatory Assets [Member] | SCEG
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	50					50
Regulatory Assets, Noncurrent	$ 37.0		$ 35.0

XML

LONG-TERM AND SHORT-TERM DEBT (Tables)

3 Months Ended

Mar. 31, 2015

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	March 31, 2015			December 31, 2014			March 31, 2015			December 31, 2014			March 31, 2015		December 31, 2014
Lines of credit:
Total committed long-term	$	300		$	300		$	1,400		$	1,400		$	100	$	100
Outstanding commercial paper (270 or fewer days)	$	15		$	179		$	610		$	709		—		30
Weighted average interest rate	0.65		%	0.54		%	0.54		%	0.52		%	—		0.65		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—		—
Available	$	282		$	118		$	790		$	691		$	100	$	70

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	March 31, 2015			December 31, 2014
Lines of credit:
Total committed long-term	$	1,400		$	1,400
Outstanding commercial paper (270 or fewer days)	$	610		$	709
Weighted average interest rate	0.54		%	0.52		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	790		$	691

XML

Dispositions (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Public Utilities, Property, Plant and Equipment, Net	$ 12,410.0	$ 12,232.0
Nonutility Property and Investments, Net	477.0	472.0
Assets, Current	1,435.0	2,145.0
Regulated Entity, Other Assets, Noncurrent	2,084.0	2,003.0
Assets held for sale	0	341.0
Liabilities, Current	1,732.0	2,533.0
Liabilities, Noncurrent	3,824.0	3,801.0
Liabilities held for sale		52.0
Estimated pre-tax gain on sale of CGT and SCI	342
Assets Held-for-sale [Member] | CGT [Member]
Public Utilities, Property, Plant and Equipment, Net		288.4
Nonutility Property and Investments, Net		0.6
Assets, Current		6.5
Regulated Entity, Other Assets, Noncurrent		0.9
Assets held for sale		296.4
Assets Held-for-sale [Member] | SCANA Communications [Member]
Public Utilities, Property, Plant and Equipment, Net		0
Nonutility Property and Investments, Net		40.1
Assets, Current		3.9
Regulated Entity, Other Assets, Noncurrent		0.2
Assets held for sale		44.2
Assets Held-for-sale [Member] | Held for Sale, CGT and SCI [Member]
Public Utilities, Property, Plant and Equipment, Net		288.4
Nonutility Property and Investments, Net		40.7
Assets, Current		10.4
Regulated Entity, Other Assets, Noncurrent		1.1
Assets held for sale		340.6
Liabilities, Held for Sale [Member] | CGT [Member]
Liabilities, Current		3.5
Liabilities, Noncurrent		42.9
Liabilities held for sale		46.4
Liabilities, Held for Sale [Member] | SCANA Communications [Member]
Liabilities, Current		2.2
Liabilities, Noncurrent		3.1
Liabilities held for sale		5.3
Liabilities, Held for Sale [Member] | Held for Sale, CGT and SCI [Member]
Liabilities, Current		5.7
Liabilities, Noncurrent		46.0
Liabilities held for sale		$ 51.7

XML

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Credit Risk) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	$ 233.5	$ 152.4
Additional Collateral, Aggregate Fair Value	141.7	129.8
Derivative, Net Liability Position, Aggregate Fair Value	375.2	282.2
LetterofCreditAvailableCommodityDerivatives,assetposition	3.0	9.2
Commodity Derivative, net asset position	19.0	20.0
SCEG
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	188.6	107.1
Additional Collateral, Aggregate Fair Value	140.7	125.9
Derivative, Net Liability Position, Aggregate Fair Value	$ 329.3	$ 233.0

XML

LONG-TERM AND SHORT-TERM DEBT (Details 2) (USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,800,000,000
Commercial Paper Maximum Term	Outstanding commercial paper (270 or fewer days)
Number of other banks (in entities)	2
Bank of America, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	10.70%
Morgan Stanly Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	10.70%
Credit Suisse AG, Cayman Islands Branch (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	10.70%
JPMorgan Chase Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	8.90%
Mizuho Corporate Bank, Ltd (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	8.90%
TD Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	8.90%
UBS Loan Finance LLC (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	8.90%
Deutsche Bank AG New York Branch [Member] [Member]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	6.30%
Union Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	6.30%
US Bank National Association (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	6.30%
Two other banks [Domain]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	6.00%
JP Morgan Chase, Mizuho Corp, TD Bank, Credit Suisse AG ,Cayman Islands Branch and UBS Loan Finance [Member]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	8.90%
SCEG
Debt Instrument [Line Items]
Due to Affiliate, Current	365,000,000	180,000,000
Debt Instruments [Abstract]
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	1,200,000,000
3 year credit agreement	200,000,000
Number of other banks (in entities)	2
Related Party Transaction, Due from (to) Related Party, Current	275,500,000	83,000,000
Due from Other Related Parties, Current		80,000,000
SCEG | Bank of America, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	10.70%
SCEG | Morgan Stanly Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	10.70%
SCEG | Credit Suisse AG, Cayman Islands Branch (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	10.70%
SCEG | JPMorgan Chase Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	8.90%
SCEG | Mizuho Corporate Bank, Ltd (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	8.90%
SCEG | TD Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	8.90%
SCEG | UBS Loan Finance LLC (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	8.90%
SCEG | Deutsche Bank AG New York Branch [Member] [Member]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	6.30%
SCEG | Union Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	6.30%
SCEG | US Bank National Association (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	6.30%
SCEG | Two other banks [Domain]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	6.00%
SCEG | JP Morgan Chase, Mizuho Corp, TD Bank, Credit Suisse AG ,Cayman Islands Branch and UBS Loan Finance [Member]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	8.90%
Parent Company [Member]
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity	300,000,000	300,000,000
Commercial Paper	15,000,000	179,000,000
Commercial paper, weighted average interest rate (as a percent)	0.65%	0.54%
Letters of credit supported by LOC	3,000,000	3,000,000
Line of Credit Facility, Remaining Borrowing Capacity	282,000,000	118,000,000
SCE&G (including Fuel Company)
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity	1,400,000,000	1,400,000,000
Commercial Paper	610,000,000	709,000,000
Commercial paper, weighted average interest rate (as a percent)	0.54%	0.52%
Commercial Paper Maximum Term	Outstanding commercial paper (270 or fewer days)
Letters of credit supported by LOC	(300,000)	300,000
Line of Credit Facility, Remaining Borrowing Capacity	790,000,000	691,000,000
3 year credit agreement	200,000,000
Long-term Line of Credit	1,400,000,000
Fuel Company
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity	500,000,000
PSNC Energy
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity	100,000,000	100,000,000
Commercial Paper	0	30,000,000
Commercial paper, weighted average interest rate (as a percent)	0.00%	0.65%
Letters of credit supported by LOC	0	0
Line of Credit Facility, Remaining Borrowing Capacity	$ 100,000,000	$ 70,000,000

XML

COMMITMENTS AND CONTINGENCIES (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2014
Environmental
NPDES permit renewal permit period	five
MIlestones Extended	3
ForecastedCapitalCostsApproved2012Order	$ 4,548,000,000
Regulatory Assets, Noncurrent	1,890,000,000				1,823,000,000
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	19,200,000
Deferred costs net of costs previously recovered through rates and insurance settlements included in regulatory assets	35,200,000
Current ownership share in New Unit	55.00%
Total additional ownership in new units	5.00%
Additional ownership in new units		0.00%	2.00%	1.00%
Additional ownership in new units, dollars	500,000,000
Total Construction Milestones	146
Milestone Schedule Contingency Period	18
Completed Construction Milestones	105
MIlestones Extended	3
Forecasted incremental capital costs, 2015 petition	698,000,000
Regulatory Assets, Noncurrent	1,817,000,000				1,745,000,000
PSNC Energy
Environmental
Number of MGP sites requiring cleanup	5
Regulatory Assets, Noncurrent	1,000,000
Summer Station New Units [Domain]
Nuclear Insurance
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	2,900,000,000
jointly owned utility plant ownership, construction financing cost	2,425,000,000
Environmental
Jointly Owned Utility Plant, Proportionate Ownership Share	55.00%
Nuclear Production Tax Credits	1,400,000,000
Nuclear Production Tax Credit realization period	8
Summer Station New Units [Domain] | SCEG
Environmental
Jointly Owned Utility Plant, Proportionate Ownership Share	55.00%
Nuclear Production Tax Credits	1,400,000,000
Nuclear Production Tax Credit realization period	8
Grossconstructioncosts [Member]
Environmental
ForecastedCapitalCostsApproved2012Order	5,755,000,000
Capital costs, owners [Domain]
Environmental
Forecasted incremental capital costs, 2015 petition	245,000,000
Capital costs, owners [Domain] | SCEG
Environmental
Forecasted incremental capital costs, 2015 petition	245,000,000
Capital costs, Other [Domain] [Domain]
Environmental
Forecasted incremental capital costs, 2015 petition	453,000,000
Capital costs, Other [Domain] [Domain] | SCEG
Environmental
Forecasted incremental capital costs, 2015 petition	$ 453,000,000

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Interest Paid, Capitalized	$ 3	$ 3
SCEG
Interest Paid, Capitalized	$ 3	$ 3

XML

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments Offsetting Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Asset	$ 0	$ 0
Derivative Liability	379	289
Derivative, Collateral, Right to Reclaim Securities	0	0
Derivative Asset, Fair Value, Gross Asset	20	21
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset	20	21
Derivative, Collateral, Obligation to Return Securities	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	20	21
Derivative, Collateral, Right to Reclaim Cash	(233)	(152)
Derivative Liability, Fair Value, Amount Offset Against Collateral	146	137
Derivative Liability, Fair Value, Gross Liability	379	289
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	6	5
Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability	4	6
Derivative Asset	14	16
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	306	233
Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	69	50
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability	355	257
Derivative, Collateral, Right to Reclaim Securities	0	0
Derivative, Collateral, Right to Reclaim Cash	(216)	(131)
Derivative Liability, Fair Value, Amount Offset Against Collateral	139	126
Derivative Liability, Fair Value, Gross Liability	355	257
Commodity Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability	5	12
Derivative, Collateral, Right to Reclaim Securities	0	0
Derivative Asset, Fair Value, Gross Asset	1	1
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset	1	1
Derivative, Collateral, Obligation to Return Securities		0
Derivative Asset, Fair Value, Amount Offset Against Collateral	1	1
Derivative, Collateral, Right to Reclaim Cash	(4)	(10)
Derivative Liability, Fair Value, Amount Offset Against Collateral	1	2
Derivative Liability, Fair Value, Gross Liability	5	12
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability	19	20
Derivative, Collateral, Right to Reclaim Securities	0	0
Derivative Asset, Fair Value, Gross Asset	19	20
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset	19	20
Derivative, Collateral, Obligation to Return Securities	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	19	20
Derivative, Collateral, Right to Reclaim Cash	(13)	(11)
Derivative Liability, Fair Value, Amount Offset Against Collateral	6	9
Derivative Liability, Fair Value, Gross Liability	19	20
SCEG
Derivative [Line Items]
Derivative Liability	329	233
SCEG | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	289	208
SCEG | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	40	25
SCEG | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability	329	233
Derivative, Collateral, Right to Reclaim Securities	0	0
Derivative, Collateral, Right to Reclaim Cash	(189)	(107)
Derivative Liability, Fair Value, Amount Offset Against Collateral	140	126
Derivative Liability, Fair Value, Gross Liability	$ 329	$ 233

XML

SEGMENT OF BUSINESS INFORMATION (Tables)

3 Months Ended

Mar. 31, 2015

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 March 31, 2015
Electric Operations	$	629		—			$	199	n/a
Gas Distribution	368			—			96		n/a
Retail Gas Marketing	204			—			n/a		$	27
Energy Marketing	187			$	35		n/a		6
All Other	4			114			238		207
Adjustments/Eliminations	(3		)	(149		)	53		160
Consolidated Total	$	1,389		$	—		$	586	$	400

Three Months Ended March 31, 2014
Electric Operations	$	678		$	2		$	198	n/a
Gas Distribution	455			—			97		n/a
Retail Gas Marketing	220			—			n/a		$	22
Energy Marketing	234			53			n/a		7
All Other	9			110			8		4
Adjustments/Eliminations	(6		)	(165		)	47		160
Consolidated Total	$	1,590		$	—		$	350	$	193

	March 31,		December 31,
Segment Assets	2015		2014
Electric Operations	$	10,300	$	10,182
Gas Distribution	2,504		2,487
Retail Gas Marketing	155		140
Energy Marketing	128		150
All Other	1,494		1,474
Adjustments/Eliminations	1,825		2,419
Consolidated Total	$	16,406	$	16,852

SCEG

Segment Reporting Information [Line Items]

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

.

Millions of dollars	External Revenue		Operating Income		Earnings Available to Common Shareholder
Three Months Ended March 31, 2015
Electric Operations	$	630	$	199	n/a
Gas Distribution	142		38		n/a
Adjustments/Eliminations	—		—		$	122
Consolidated Total	$	772	$	237	$	122

Three Months Ended March 31, 2014
Electric Operations	$	680	$	198	n/a
Gas Distribution	179		41		n/a
Adjustments/Eliminations	—		—		$	123
Consolidated Total	$	859	$	239	$	123

Segment Assets	March 31, 2015		December 31, 2014
Electric Operations	$	10,300	$	10,182
Gas Distribution	731		721
Adjustments/Eliminations	3,103		3,204
Consolidated Total	$	14,134	$	14,107

XML

EMPLOYEE BENEFIT PLANS (Tables)

3 Months Ended

Mar. 31, 2015

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

: 

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2015			2014			2015		2014
Three months ended March 31,
Service cost	$	5.8		$	5.0		$	1.4	$	1.2
Interest cost	9.5			10.2			2.9		3.1
Expected return on assets	(15.5		)	(16.8		)	—		—
Prior service cost amortization	1.0			1.0			0.1		0.1
Amortization of actuarial losses	3.5			1.3			0.6		0.1
Net periodic benefit cost	$	4.3		$	0.7		$	5.0	$	4.5

SCEG

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

:

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2015			2014			2015		2014
Three months ended March 31,
Service cost	$	4.6		$	4.0		$	1.1	$	1.0
Interest cost	8.0			8.6			2.3		2.4
Expected return on assets	(13.0		)	(14.2		)	—		—
Prior service cost amortization	0.8			0.9			0.1		0.1
Amortization of actuarial losses	3.0			1.1			0.4		0.1
Net periodic benefit cost	$	3.4		$	0.4		$	3.9	$	3.6

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	$ 20	$ 21
Derivative Liability	379	289
Available-for-sale Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	13	13
Available-for-sale Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	0	0
Interest Rate Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability	355	257
Interest Rate Contract | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability	0	0
Interest Rate Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability	355	257
Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	1	1
Derivative Liability	5	12
Commodity Contract | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	1	1
Derivative Liability	0	1
Commodity Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	0	0
Derivative Liability	0	11
Other energy management contracts [Member] [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	19	20
Derivative Liability	19	20
Other energy management contracts [Member] [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	0	0
Derivative Liability	3	5
Other energy management contracts [Member] [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	19	20
Derivative Liability	23	18
SCEG
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability	329	233
SCEG | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability	329	233
SCEG | Interest Rate Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability	$ 329	$ 233

XML

Dispositions (Tables)

3 Months Ended

Mar. 31, 2015

Disposal groups [Abstract]

Schedule of Disposal Group, Held for Sale [Table Text Block]

Millions of dollars	CGT		SCI		Total
Assets Held for Sale
Utility Plant, Net	$	288.4	—		$	288.4
Nonutility Property and Investments, Net	0.6		$	40.1	40.7
Current Assets	6.5		3.9		10.4
Deferred Debits and Other Assets	0.9		0.2		1.1
Total Assets Held for Sale	296.4		44.2		340.6
Liabilities Held for Sale
Current Liabilities	$	3.5	$	2.2	$	5.7
Deferred Credits and Other Liabilities	42.9		3.1		46.0
Total Liabilities Held for Sale	$	46.4	$	5.3	$	51.7

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Management and Supply Service Agreements
Property, Plant and Equipment, Net	$ 285	$ 284
SCEG
Significant Accounting Policies
Number of coal fired units to be retired	3			6
Number of Units retired	3		3
Asset Management and Supply Service Agreements
Property, Plant and Equipment, Net	67	67
Genco
Significant Accounting Policies
Power Generation Capacity Megawatts	605
Asset Management and Supply Service Agreements
Property, Plant and Equipment, Net	498
PSNC Energy [Member]
Asset Management and Supply Service Agreements
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)	32.00%	48.00%
Natural gas inventory, carrying amount	$ 8.7	$ 26.1
PercentOfStorageFeesCreditedToRatePayers	75.00%

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Cash Flows From Operating Activities:
Net Income (Loss) Available to Common Stockholders, Basic	$ 400	$ 193
Adjustments to reconcile net income to net cash provided from operating activities:
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal	(353)
Income (Loss) from Equity Method Investments, Net of Dividends or Distributions	1	1
Deferred Income Tax Expense (Benefit)	(74)	7
Depreciation and amortization	100	99
Amortization of nuclear fuel	13	15
Allowance for equity funds used during construction	(5)	(7)
Carrying cost recovery	(3)	(2)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	33	(56)
Inventories	31	70
Increase (Decrease) in Prepaid Expense	(218)	(12)
Increase (Decrease) in Other Regulatory Assets	(68)	(108)
Regulatory liabilities	6	(94)
Accounts payable	(67)	29
Taxes accrued	(71)	(143)
Interest accrued	(7)	(7)
Increase (Decrease) in Pension and Postretirement Obligations	(1)	(2)
Increase (Decrease) in Derivative Assets and Liabilities	59	39
Changes in other assets	(6)	11
Changes in other liabilities	(11)	81
Net Cash Provided From Operating Activities	195	138
Cash Flows From Investing Activities:
Property additions and construction expenditures	(352)	(289)
Proceeds from Sale of Property, Plant, and Equipment	645
Proceeds from investments (including derivative collateral posted)	318	16
Purchase of investments (including derivative collateral posted)	(400)	(22)
Net Cash Used in Investing Activities	211	(295)
Cash Flows From Financing Activities:
Proceeds from Issuance of Common Stock	14	22
Repayments of Long-term Debt	(158)	(9)
Dividends	(75)	(66)
Short-term borrowings, net	(293)	184
Net Cash Provided From Financing Activities	(512)	131
Net (Decrease) Increase in Cash and Cash Equivalents	(106)	(26)
Cash and Cash Equivalents, January 1	137	136
Cash and Cash Equivalents, March 31	31	110
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	81	80
Cash paid for-Income taxes	8	100
Noncash Investing and Financing Activities:
Accrued construction expenditures	84	77
Capital Lease Obligations Incurred	2	1
SCEG
Cash Flows From Operating Activities:
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	126	126
Adjustments to reconcile net income to net cash provided from operating activities:
Income (Loss) from Equity Method Investments	1	1
Deferred Income Tax Expense (Benefit)	7	5
Depreciation and amortization	82	78
Amortization of nuclear fuel	13	15
Allowance for equity funds used during construction	(5)	(5)
Carrying cost recovery	(3)	(2)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	22	(23)
Inventories	0	19
Increase (Decrease) in Prepaid Expense	(75)	(7)
Increase (Decrease) in Other Regulatory Assets	(74)	(107)
Regulatory liabilities	6	(94)
Accounts payable	(20)	27
Taxes accrued	(50)	(127)
Interest accrued	(7)	(11)
Increase (Decrease) in Pension and Postretirement Obligations	22	(2)
Increase (Decrease) in Derivative Assets and Liabilities	81	40
Changes in other assets	(3)	15
Changes in other liabilities	(49)	81
Net Cash Provided From Operating Activities	224	43
Cash Flows From Investing Activities:
Property additions and construction expenditures	(319)	(260)
Proceeds from investments (including derivative collateral posted)	274	4
Purchase of investments (including derivative collateral posted)	(356)	(9)
Investment In Affiliate	80
Net Cash Used in Investing Activities	(321)	(265)
Cash Flows From Financing Activities:
Repayments of Long-term Debt	(8)	(9)
Dividends	(74)	(62)
Contributions from parent	(4)	20
Short-term borrowings, net	(99)	206
Short-term borrowings-affiliate,net	192	7
Net Cash Provided From Financing Activities	7	162
Net (Decrease) Increase in Cash and Cash Equivalents	(90)	(60)
Cash and Cash Equivalents, January 1	100	92
Cash and Cash Equivalents, March 31	10	32
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	62	62
Cash paid for-Income taxes	(83)	59
Noncash Investing and Financing Activities:
Accrued construction expenditures	76	97
Capital Lease Obligations Incurred	$ 2	$ 1

XML

RATE AND OTHER REGULATORY MATTERS (Details) (USD $)	3 Months Ended		12 Months Ended		9 Months Ended	12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2014	Dec. 31, 2015	Mar. 31, 2013	Dec. 31, 2012
Rate Matters [Line Items]
Estimated undercollected base fuel and variable environmental costs	$ 36,100,000
Carrying cost recovery	(3,000,000)	(2,000,000)
Regulatory Assets, Noncurrent	1,890,000,000		1,823,000,000
Public Utilities Base Fuel under Collected Balance Recovery Period	12
SCEG
Rate Matters [Line Items]
Forecasted incremental capital costs, 2015 petition	698,000,000
Forecasted Capital Cost, 2015 Petition	5,200,000,000
Amounts Recovered Through Electric Rates to offset Nuclear Related Outage Costs	17,200,000
Net Lost Revenues associated with DSM programs			6,600,000
Fuel Costs	10,300,000
Undercollected balance fuel	46,000,000
Estimated undercollected base fuel and variable environmental costs	36,100,000
Carrying costs on deferred income tax assets	1,900,000	1,200,000
Carrying cost recovery	(3,000,000)	(2,000,000)
Regulatory Assets, Noncurrent	1,817,000,000		1,745,000,000
Number of coal fired units to be retired	3							6
Allowable return on common equity (as a percent)	11.00%
Demand Side Management Program Costs, Noncurrent	32,000,000	15,400,000					16,900,000
Regulatory Asset Recovery Assessments		12
Increase (decrease) in retail electric rate requested under the BLRA			66,200,000	67,200,000
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates			2.80%	2.90%
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates			0.60%
Public Utilities changes in Retail Natural Gas Rates Approved under RSA			2,600,000
Public Utilities, Rate Calculation Basis	12-month rolling average
Public Utilities Base Fuel under Collected Balance Recovery Period	12
Derivative, Gain on Derivative			17,800,000
Storm Damage Reserve Cost Applied			5,000,000
Reduction to Net Lost Revenues from DSM programs			25.00%
Reduction to DSM Program costs deferred			6,600,000
Number of Units retired	3			3
Demand side management recovery period	5
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs	100,000,000
PSNC Energy
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	1,000,000
Public Utilities, Rate Calculation Basis		12
Pension Costs [Member]
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	337,000,000		350,000,000
Pension Costs [Member] | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	305,000,000		310,000,000
Regulatory Noncurrent Asset Amortization Period	12		14	30
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	14,000,000							63,000,000
Other Regulatory Assets [Member]
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	37,000,000		35,000,000
Regulatory Noncurrent Asset Amortization Period	30				30
Other Regulatory Assets [Member] | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	37,000,000		35,000,000
Regulatory Noncurrent Asset Amortization Period	50					50
Deferred Pollution Control Costs
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	35,000,000		36,000,000
Deferred Pollution Control Costs | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	35,000,000		36,000,000
Franchise agreement Costs
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	25,000,000		26,000,000
Franchise agreement Costs | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	25,000,000		26,000,000
Capital costs, construction delays [Domain] | SCEG
Rate Matters [Line Items]
Forecasted incremental capital costs, 2015 petition	539,000,000
Grossconstructioncosts [Member] | SCEG
Rate Matters [Line Items]
Forecasted Capital Cost, 2015 Petition	6,800,000,000
Planned major maintenance [Member] | SCEG
Rate Matters [Line Items]
Amounts Recovered through Electric Rates to offset Turbine Expense	18,400,000
Storm damage reserve [Member]
Rate Matters [Line Items]
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM			5,000,000
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs	$ 100,000,000

XML

DERIVATIVE FINANCIAL INSTRUMENTS Fair Value on Balance Sheet (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative Asset	$ 20	$ 21
Derivative Liability	379	289
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	6	5
Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	69	50
Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset	14	16
Derivative Liability	4	6
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability	355	257
Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset	1	1
Derivative Liability	5	12
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Asset	19	20
Derivative Liability	19	20
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability	42	45
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	4	5
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	33	28
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	4	11
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability	1	1
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset	20	21
Derivative Liability	337	244
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	288	207
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	30	17
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset	1	1
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	10	10
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	6	5
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	6	5
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset	13	15
Derivative Liability	3	5
SCEG
Derivative [Line Items]
Derivative Liability	329	233
SCEG | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	40	25
SCEG | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability	329	233
SCEG | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability	11	9
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	1	1
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	10	8
SCEG | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability	318	224
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	288	207
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	$ 30	$ 17

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Assets
Utility Plant In Service	$ 12,382	$ 12,289
Accumulated Depreciation and Amortization	(4,141)	(4,088)
Construction Work in Progress	3,478	3,323
Plant to be Retired, Net	164	169
Nuclear Fuel, Net of Accumulated Amortization	317	329
Goodwill, Net of Writedown of $230	210	210
Utility Plant, Net	12,410.0	12,232.0
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	285	284
Assets held in trust, net-nuclear decommissioning	115	113
Other investments	77	75
Nonutility Property and Investments, Net	477.0	472.0
Current Assets:
Cash and cash equivalents	31	137
Receivables, net of allowance for uncollectible accounts	778	838
Inventories (at average cost):
Fuel	175	222
Materials and supplies	143	139
Prepaid Expense	104	320
Other current assets	204	148
Assets held for sale	0	341.0
Total Current Assets	1,435.0	2,145.0
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	1,890.0	1,823.0
Other	194	180
Total Deferred Debits and Other Assets	2,084.0	2,003.0
Total	16,406	16,852
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,392	2,378
Retained Earnings, Unappropriated	3,006	2,684
Accumulated Other Comprehensive Income (Loss), Net of Tax	(73)	(75)
Common equity	5,325	4,987
Long-term Debt, Excluding Current Maturities	5,525	5,531
Total Capitalization	10,850	10,518
Current Liabilities:
Short-term borrowings	625	918
Current portion of long-term debt	16	166
Accounts payable	331	520
Customer deposits and customer prepayments	109	98
Taxes accrued	110	182
Interest accrued	76	83
Dividends declared	76	73
Liabilities held for sale		52.0
Derivative financial instruments	292	233
Other	97	208
Total Current Liabilities	1,732.0	2,533.0
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,863	1,866
Deferred investment tax credits	27	28
Asset retirement obligations	566	563
Pension and other postretirement benefits	316	315
Regulatory Liabilities	829	814
Other	223	215
Total Deferred Credits and Other Liabilities	3,824.0	3,801.0
Total	16,406	16,852
SCEG
Assets
Utility Plant In Service	10,739	10,650
Accumulated Depreciation and Amortization	(3,716)	(3,667)
Construction Work in Progress	3,451	3,302
Plant to be Retired, Net	164	169
Nuclear Fuel, Net of Accumulated Amortization	317	329
Utility Plant, Net	10,955.0	10,783.0
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	67	67
Assets held in trust, net-nuclear decommissioning	115	113
Other investments	2	2
Nonutility Property and Investments, Net	184.0	182.0
Current Assets:
Cash and cash equivalents	10	100
Receivables, net of allowance for uncollectible accounts	490	524
Due from Affiliate, Current	19.0	109.0
Inventories (at average cost):
Fuel	119	131
Materials and supplies	131	129
Prepaid Expense	79	154
Other current assets	170	99
Total Current Assets	1,018.0	1,246.0
Deferred Debits and Other Assets:
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	11	10
Regulatory Assets, Noncurrent	1,817.0	1,745.0
Other	149	141
Total Deferred Debits and Other Assets	1,977.0	1,896.0
Total	14,134	14,107
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,556	2,560
Retained Earnings, Unappropriated	2,130	2,077
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3)	(3)
Common equity	4,683	4,634
Stockholders' Equity Attributable to Noncontrolling Interest	126	123
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	4,809	4,757
Long-term Debt, Excluding Current Maturities	4,293	4,299
Total Capitalization	9,102	9,056
Current Liabilities:
Short-term borrowings	610	709
Current portion of long-term debt	10	10
Accounts payable	181	294
Due to Affiliate, Current	365.0	180.0
Customer deposits and customer prepayments	66	61
Taxes accrued	120	170
Interest accrued	57	64
Dividends declared	71	74
Derivative financial instruments	289	208
Other	45	99
Total Current Liabilities	1,814.0	1,869.0
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,703	1,696
Deferred investment tax credits	27	28
Asset retirement obligations	539	536
Pension and other postretirement benefits	220	195
Regulatory Liabilities	621	610
Other	108	117
Total Deferred Credits and Other Liabilities	3,218.0	3,182.0
Total	$ 14,134	$ 14,107

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 5,541.6	$ 5,697.2
Long-term Debt, Fair Value	6,501.6	6,592.1
SCEG
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	4,303.3	4,308.6
Long-term Debt, Fair Value	$ 5,119.2	$ 5,070.9

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Net Income (Loss) Attributable to Parent [Abstract]
Net Income (Loss) Available to Common Stockholders, Basic	$ 400	$ 193
Other Comprehensive Income (Loss)
Unrealized gains (losses) on cash flow hedging activities arising during period	(3)	1
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	6	(1)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Reclassification Adjustments, Net of Tax	(4)	0
Other Comprehensive Income (Loss)	2	(1)
SCEG
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	126	126
Other Comprehensive Income (Loss)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	126	126
Genco
Other Comprehensive Income (Loss)
Less comprehensive income attributable to noncontrolling interest	4	3
SCE&G (including Fuel Company)
Net Income (Loss) Attributable to Parent [Abstract]
Net Income (Loss) Available to Common Stockholders, Basic	122	123
Commodity Contract
Other Comprehensive Income (Loss)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	7	(4)
Interest Rate Contract
Other Comprehensive Income (Loss)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	2	2
Cash Flow Hedging [Member] | Interest Expense [Member] | Interest Rate Contract
Other Comprehensive Income (Loss)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ (2)	$ (2)

XML

COMMON EQUITY (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	200		200
COMMON EQUITY [Abstract]
Dividends declared	$ (78)	$ (74)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	6	(1)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	(4)
Other Comprehensive Income (Loss), Net of Tax	2	(1)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	402	192
Stock Issued During Period, Value, New Issues	14	27
Common Stock, Shares, Outstanding	143	141	143	141
Common Stock, Value, Outstanding	2,392	2,307	2,378	2,280
Accumulated Other Comprehensive Income (Loss), Net of Tax	(73)	(61)	(75)	(60)
Retained Earnings, Unappropriated	3,006	2,563	2,684	2,444
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	3	1
Income Available to Common Shareholders	400	193
Common equity	5,325	4,809	4,987	4,664
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(57)	(53)	(63)	(52)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(16)	(8)	(12)	(8)
SCEG
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares, Issued	40	40	40	40
Common Stock, Shares Authorized	50		50
COMMON EQUITY [Abstract]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	126	126
Proceeds from Contributions from Parent	(4)	20
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	0	0
Net Income (Loss) Attributable to Noncontrolling Interest	4	3
Dividends	(70)	(64)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	126	126
Common Stock, Shares, Outstanding	40		40
Preferred Stock, Shares Authorized	20		20
Preferred Stock, Shares Outstanding	0		0
Common Stock, Value, Outstanding	2,556		2,560
Preferred Stock, Value, Issued	0		0
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3)		(3)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	4,809	4,571	4,757	4,489
Retained Earnings, Unappropriated	2,130		2,077
Reclassifcations of deferred employee benefit costs	not significant
Common equity	4,683		4,634
SCEG excluding VIEs [Member]
COMMON EQUITY [Abstract]
Proceeds from Contributions from Parent	(4)	20
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	0	0
Dividends	(69)	62
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	122	123
Common Stock, Value, Outstanding	2,556	2,499	2,560	2,479
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3)	(3)	(3)	(3)
Retained Earnings, Unappropriated	2,130	1,957	2,077	1,896
Income Available to Common Shareholders	122	123
Noncontrolling Interest [Member]
COMMON EQUITY [Abstract]
Net Income (Loss) Attributable to Noncontrolling Interest	4	3
Dividends	1	2
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	126	118	123	117
Interest Rate Contract
COMMON EQUITY [Abstract]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2)	(2)
Commodity Contract
COMMON EQUITY [Abstract]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(7)	4
Interest Expense [Member] | Cash Flow Hedging [Member] | Interest Rate Contract
COMMON EQUITY [Abstract]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	2	2
Gas Purchased for Resale [Member] [Member]
COMMON EQUITY [Abstract]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(7)
Gas Purchased for Resale [Member] [Member] | Cash Flow Hedging [Member] | Commodity Contract
COMMON EQUITY [Abstract]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 7	$ (4)

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

3 Months Ended

Mar. 31, 2015

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.

Plant to be retired [Policy Text Block]

Plant to be Retired

SCE&G expects to retire three units that are or were coal-fired by 2020, subject to future developments in environmental regulations, among other matters. The net carrying value of these units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. The net carrying value of three previously retired units is recorded in regulatory assets within unrecovered plant (see Note 2).

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.  There were no securities considered to be dilutive potential common stock during any period presented. The Company has issued no securities that would have an antidilutive effect on earnings per share.

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 32% and 48% of PSNC Energy’s natural gas inventory at March 31, 2015

and December 31, 2014, respectively, with a carrying value of $8.7 million and $26.1 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, which expired on March 31, 2015, have been replaced with similar agreements that expire March 31, 2017.

Income Statement policy [Policy Text Block]

Income Statement Presentation

The Company presents the revenues and expenses of its regulated businesses and its retail natural gas marketing businesses (including those activities of segments described in Note 10) within operating income, and it presents all other activities within other income (expense). Consistent with this presentation, the gain on the sale of CGT is reflected within operating income and the gain on the sale of SCI is reflected within other income (expense).

SCEG

Significant Accounting Policies

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

Variable Interest Entities

SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, the accompanying condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. Accordingly, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements.

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $498 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

SCE&G expects to retire three units that are or were coal-fired by 2020, subject to future developments in environmental regulations, among other matters. The net carrying value of these units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. The net carrying value of three previously retired units is recorded in regulatory assets within unrecovered plant (see Note 2).

XML

LONG-TERM AND SHORT-TERM DEBT (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	6 Months Ended
	Mar. 31, 2015	Jun. 30, 2014	Dec. 31, 2014
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,800.0
Commercial Paper Maximum Term	Outstanding commercial paper (270 or fewer days)
Number of other banks (in entities)	2
Long-term Debt, Current Maturities	16		166
Debt Instrument, Interest Rate Terms	0.077
Junior Subordinated Notes	150
Credit Suisse AG, Cayman Islands Branch (Member)
Debt Instrument [Line Items]
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	8.90%
Branch Banking Trust Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	6.30%
SCE&G (including Fuel Company)
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,400.0		1,400.0
Commercial Paper Maximum Term	Outstanding commercial paper (270 or fewer days)
Commercial Paper	(610)		(709)
Debt, Weighted Average Interest Rate	0.54%		0.52%
Letters of Credit Outstanding, Amount	0.3		(0.3)
Line of Credit Facility, Remaining Borrowing Capacity	790		691
SCEG
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bond		300
Line of Credit Facility, Maximum Borrowing Capacity	1,200.0
Number of other banks (in entities)	2
Long-term Debt, Current Maturities	10		10
Debt Instrument, Face Amount	67.8
Debt Instrument, Interest Rate Terms		.045
SCEG | Credit Suisse AG, Cayman Islands Branch (Member)
Debt Instrument [Line Items]
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	8.90%
SCEG | Branch Banking Trust Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	8.90%
PSNC Energy [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	100.0		100.0
Commercial Paper	0		(30)
Debt, Weighted Average Interest Rate	0.00%		0.65%
Letters of Credit Outstanding, Amount	0		0
Line of Credit Facility, Remaining Borrowing Capacity	100		70
Fuel Company
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 500.0

XML

COMMON EQUITY (Tables)

3 Months Ended

Mar. 31, 2015

Schedule of Capitalization, Equity [Line Items]

Schedule of Stockholders Equity [Table Text Block]

	Common Stock						Accumulated Other Comprehensive Income (Loss)
Millions	Shares	Amount		Retained Earnings			Gains(Losses) on Cash Flow Hedges			Deferred Employee Benefit Plans			Total AOCI			Total Common Equity
Balance as of January 1, 2015	143	$	2,378	$	2,684		$	(63	)	$	(12	)	$	(75	)	$	4,987
Net Income				400												400
Other Comprehensive Income (Loss):
Losses arising during the period							(3		)	(4		)	(7		)	(7		)
Gains/amortization reclassified from AOCI							9			—			9			9
Total Comprehensive Income (Loss)				400			6			(4		)	2			402
Issuance of Common Stock	—	14														14
Dividends Declared				(78		)										(78		)
Balance as of March 31, 2015	143	$	2,392	$	3,006		$	(57	)	$	(16	)	$	(73	)	$	5,325
Balance as of January 1, 2014	141	$	2,280	$	2,444		$	(52	)	$	(8	)	$	(60	)	$	4,664
Net Income				193												193
Other Comprehensive Income:
Gains arising during the period							1			—			1			1
Losses/amortization reclassified from AOCI							(2		)	—			(2		)	(2		)
Total Comprehensive Income				193			(1		)	—			(1		)	192
Issuance of Common Stock	—	27														27
Dividends Declared				(74		)										(74		)
Balance as of March 31, 2014	141	$	2,307	$	2,563		$	(53	)	$	(8	)	$	(61	)	$	4,809

SCEG

Schedule of Capitalization, Equity [Line Items]

Schedule of Stockholders Equity [Table Text Block]

Changes in common equity during the three months ended March 31, 2015 and 2014 were as follows:

	Common Stock				Retained			Accumulated Other Comprehensive			Noncontrolling			Total
Millions	Shares	Amount			Earnings			Income (Loss)			Interest			Equity
Balance at January 1, 2015	40	$	2,560		$	2,077		$	(3	)	$	123		$	4,757
Earnings available to common shareholder					122						4			126
Deferred cost of employee benefit plans								—						—
Total Comprehensive Income					122			—			4			126
Capital returned to parent		(4		)										(4		)
Cash dividend declared					(69		)				(1		)	(70		)
Balance at March 31, 2015	40	$	2,556		$	2,130		$	(3	)	$	126		$	4,809
Balance at January 1, 2014	40	$	2,479		$	1,896		$	(3	)	$	117		$	4,489
Earnings available to common shareholder					123						3			126
Deferred cost of employee benefit plans								—						—
Total Comprehensive Income					123			—			3			126
Capital contributions from parent		20												20
Cash dividend declared					(62		)				(2		)	(64		)
Balance at March 31, 2014	40	$	2,499		$	1,957		$	(3	)	$	118		$	4,571

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax	$ 0	$ 0
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(2)	1
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	1	1
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income, Tax	5	(2)
Commodity Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 7	$ (4)

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Common Stock, Shares, Outstanding	143	143
Public Utilities, Property, Plant and Equipment, Net	$ 12,410.0	$ 12,232.0
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	120	122
Allowance for Doubtful Accounts Receivable, Current	7	7
Write-down, Goodwill	230	230
Assets, Current	1,435.0	2,145.0
Regulated Entity, Other Assets, Noncurrent	2,084.0	2,003.0
SCEG
Common Stock, Shares, Outstanding	40	40
Public Utilities, Property, Plant and Equipment, Net	10,955.0	10,783.0
Allowance for Doubtful Accounts Receivable, Current	3	4
Assets, Current	1,018.0	1,246.0
Regulated Entity, Other Assets, Noncurrent	1,977.0	1,896.0
SCEG | Variable Interest Entity, Primary Beneficiary [Member]
Public Utilities, Property, Plant and Equipment, Net	716.0	675.0
Assets, Current	0	158.0
Regulated Entity, Other Assets, Noncurrent	$ 0	$ 50.0

XML

EMPLOYEE BENEFIT PLANS

3 Months Ended

Mar. 31, 2015

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	2015			2014			2015		2014
Three months ended March 31,
Service cost	$	5.8		$	5.0		$	1.4	$	1.2
Interest cost	9.5			10.2			2.9		3.1
Expected return on assets	(15.5		)	(16.8		)	—		—
Prior service cost amortization	1.0			1.0			0.1		0.1
Amortization of actuarial losses	3.5			1.3			0.6		0.1
Net periodic benefit cost	$	4.3		$	0.7		$	5.0	$	4.5

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 retired employees.  Components of net periodic benefit cost recorded by Consolidated SCE&G were as follows:

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2015			2014			2015		2014
Three months ended March 31,
Service cost	$	4.6		$	4.0		$	1.1	$	1.0
Interest cost	8.0			8.6			2.3		2.4
Expected return on assets	(13.0		)	(14.2		)	—		—
Prior service cost amortization	0.8			0.9			0.1		0.1
Amortization of actuarial losses	3.0			1.1			0.4		0.1
Net periodic benefit cost	$	3.4		$	0.4		$	3.9	$	3.6

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	3 Months Ended
	Mar. 31, 2015	Apr. 30, 2015
Entity Information [Line Items]
Entity Registrant Name	SCANA Corporation
Entity Central Index Key	0000754737
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		142,916,917
SCEG
Entity Information [Line Items]
Entity Registrant Name	SOUTH CAROLINA ELECTRIC & GAS CO
Entity Central Index Key	0000091882
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		40,296,147

XML

COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 2015

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

In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, 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%. As discussed below, 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.

EPC Contract and BLRA Matters

The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval 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 schedule contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, 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. As of March 31, 2015, SCE&G’s investment in the New Units totaled $2.9 billion, for which the financing costs on $2.4 billion have been reflected in rates under the BLRA.

The SCPSC granted initial approval of the construction schedule, including 146 milestones within that schedule, and related forecasted capital costs in 2009. The NRC issued COLs in March 2012. In November 2012, the SCPSC approved 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 that March 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 prefabricated structural modules for the New Units and unanticipated rock conditions at the site. In October 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal.

The substantial completion dates currently approved by the SCPSC for Units 2 and 3 are March 15, 2017 and May 15, 2018. The SCPSC also approved an 18-month contingency period beyond each of these dates, and for each of the 146 milestones in the schedule.

Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule, including those related to 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 CA01, which houses components inside the containment vessel. Module CA01 and shield building modules are considered critical path items for both New Units. The delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow CA01 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 was a revised, fully integrated project schedule with timing of specific construction activities (Revised, Fully-Integrated Construction Schedule) along with related cost information.

The Revised, Fully-Integrated Construction Schedule indicated that the substantial completion of Unit 2 was expected to occur in mid-June 2019 and that the substantial completion of Unit 3 was expected to be approximately 12 months later. SCE&G has not, however, accepted the Consortium's contention that the new substantial completion dates are made necessary by delays that are excusable under the EPC Contract. The Consortium continues to refine and update the Revised, Fully-Integrated Construction Schedule as designs are finalized, as construction progresses, and as additional information is received.

As discussed above, the milestone schedule approved by the SCPSC in November 2012 provides for 146 milestone dates, each of which is subject to an 18-month schedule contingency. As of April 30, 2015, 105 milestones have been completed, and three of the remaining milestones have not been completed within their 18-month contingency periods. In light of the Revised, Fully Integrated Schedule, it is anticipated that the completion dates for a substantial number of the remaining milestone dates will also extend beyond their contingency periods. Further, capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) are projected to exceed amounts currently approved by the SCPSC of $4.5 billion and $5.8 billion, respectively.

As such, in March 2015 SCE&G petitioned the SCPSC for an order to update the BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively. In addition, that petition included certain updated owner's costs ($245 million) and other capital costs ($453 million) which, if approved, would reset projected capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) to $5.2 billion and $6.8 billion, respectively. These projections include cost amounts related to the Revised, Fully-Integrated Construction Schedule for which SCE&G has not accepted responsibility and which may be the subject of dispute. As such, the petition does not reflect the resolution of negotiations.

The SCPSC will hold a public hearing related to the petition in July 2015. While 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, SCE&G cannot predict the outcome of this regulatory process. As discussed in Note 2, SCE&G expects the SCPSC to issue its order on the petition in September 2015.

Additional claims by the Consortium or SCE&G involving the project schedule and budget may arise as the project continues. The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve such issues. SCE&G expects to resolve all disputes (including any ultimate disagreements involving the preliminary cost estimates provided by the Consortium in the third quarter of 2014) 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.

Santee Cooper Matters

As noted above, 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, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost of the percentage conveyed as of the date of each 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. Based on the current milestone schedule and capital costs schedule approved by the SCPSC in November 2012, SCE&G’s estimated cost would be approximately $500 million for the additional 5% interest being acquired from Santee Cooper. This cost figure is expected to be higher in light of the delays and related costs discussed above.

Nuclear Production Tax Credits

The IRS has 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. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion. Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on the above substantial completion dates provided by the Consortium of June 2019 and June 2020 for Units 2 and 3, respectively, both New Units are expected to be operational and to qualify for the nuclear production tax credits; however, further delays in the schedule or changes in tax law could impact such conclusions. To the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers as so realized.

Other Project Matters

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. SCE&G prepared and submitted an integrated response plan for the New Units to the NRC in August 2013. That plan is currently under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units.

Environmental

The Company's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on the Company's financial condition, results of operations and cash flows. In addition, the Company often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, the Company expects to recover such expenditures and costs through existing ratemaking provisions.

SCE&G

The EPA issued 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 proposed rule was issued 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 could be constructed without carbon capture and sequestration capabilities. The Company is evaluating the proposed rule, but does not plan to construct new coal-fired units in the near future. In addition, on June 2, 2014, the EPA issued proposed emission guidelines for states to follow in developing plans to address GHG emissions from existing units. These guidelines are expected to be made final in late summer 2015, and include state-specific rate based goals for carbon dioxide emissions.

From a regulatory perspective, SCANA, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in construction activities of the New Units which are expected to reduce GHG emission levels significantly once they are completed and dispatched by potentially displacing some of the current coal-fired generation sources. These actions are expected to address many of the rules and regulations discussed herein.

In July 2011, the EPA issued the CSAPR to reduce emissions of sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, thus delaying the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and annual or ozone season nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for sulfur dioxide and nitrogen oxide and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the allowances set by the CSAPR.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective.  The rule provides up to four years for generating facilities to meet the standards, and the Company's evaluation of the rule is ongoing. The Company's decision 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 MATS. On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities. SCE&G and GENCO have received a one year extension (until April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions will allow time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants that will enhance the control of certain MATS-regulated pollutants.

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 no later than September 30, 2015. Once the rule becomes effective, state regulators will modify facility NPDES permits to match more restrictive standards, thus requiring facilities to retrofit with new wastewater treatment technologies. Compliance dates will vary by type of wastewater, and some will be based on a facility's five year permit cycle and thus may range from 2018 to 2023. Based on the proposed rule, the Company expects that wastewater treatment technology retrofits will be required at Williams and Wateree Stations and may be required at other facilities.

The CWA Section 316(b) Existing Facilities Rule became effective on October 14, 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans to ensure compliance with this rule. In addition, Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones.

On April 17, 2015, the EPA's final rule for CCR was published in the Federal Register and will become effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act. In addition, this rule imposes certain requirements on ash storage ponds at SCE&G's and GENCO's generating facilities. While this rule is still being evaluated, SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds.

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. As of December 31, 2014, 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.

 The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. 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 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 by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2017 and will cost an additional $19.2 million, which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At March 31, 2015, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $35.2 million and are included in regulatory assets.

PSNC Energy

PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. 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 $1.0 million, the estimated remaining liability at March 31, 2015. 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

In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, 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%. As discussed below, 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.

EPC Contract and BLRA Matters

The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval 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 schedule contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, 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. As of March 31, 2015, SCE&G’s investment in the New Units totaled $2.9 billion, for which the financing costs on $2.4 billion have been reflected in rates under the BLRA.

The SCPSC granted initial approval of the construction schedule, including 146 milestones within that schedule, and related forecasted capital costs in 2009. The NRC issued COLs in March 2012. In November 2012, the SCPSC approved 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 that March 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 prefabricated structural modules for the New Units and unanticipated rock conditions at the site. In October 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal.

The substantial completion dates currently approved by the SCPSC for Units 2 and 3 are March 15, 2017 and May 15, 2018. The SCPSC also approved an 18-month contingency period beyond each of these dates, and for each of the 146 milestones in the schedule.

Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule, including those related to 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 CA01, which houses components inside the containment vessel. Module CA01 and shield building modules are considered critical path items for both New Units. The delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow CA01 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 was a revised, fully integrated project schedule with timing of specific construction activities (Revised, Fully-Integrated Construction Schedule) along with related cost information.

The Revised, Fully-Integrated Construction Schedule indicated that the substantial completion of Unit 2 was expected to occur in mid-June 2019 and that the substantial completion of Unit 3 was expected to be approximately 12 months later. SCE&G has not, however, accepted the Consortium's contention that the new substantial completion dates are made necessary by delays that are excusable under the EPC Contract. The Consortium continues to refine and update the Revised, Fully-Integrated Construction Schedule as designs are finalized, as construction progresses, and as additional information is received.

As discussed above, the milestone schedule approved by the SCPSC in November 2012 provides for 146 milestone dates, each of which is subject to an 18-month schedule contingency. As of April 30, 2015, 105 milestones have been completed, and three of the remaining milestones have not been completed within their 18-month contingency periods. In light of the Revised, Fully Integrated Schedule, it is anticipated that the completion dates for a substantial number of the remaining milestone dates will also extend beyond their contingency periods. Further, capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) are projected to exceed amounts currently approved by the SCPSC of $4.5 billion and $5.8 billion, respectively.

As such, in March 2015 SCE&G petitioned the SCPSC for an order to update the BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively. In addition, that petition included certain updated owner's costs ($245 million) and other capital costs ($453 million) which, if approved, would reset projected capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) to $5.2 billion and $6.8 billion, respectively. These projections include cost amounts related to the Revised, Fully-Integrated Construction Schedule for which SCE&G has not accepted responsibility and which may be the subject of dispute. As such, the petition does not reflect the resolution of negotiations.

The SCPSC will hold a public hearing related to the petition in July 2015. While 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, SCE&G cannot predict the outcome of this regulatory process. As described in Note 2, SCE&G expects the SCPSC to issue its order on the petition in September 2015.

Additional claims by the Consortium or SCE&G involving the project schedule and budget may arise as the project continues. The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve such issues. SCE&G expects to resolve all disputes (including any ultimate disagreements involving the preliminary cost estimates provided by the Consortium in the third quarter of 2014) 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.

Santee Cooper Matters

As noted above, 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, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost of the percentage conveyed as of the date of each 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. Based on the current milestone schedule and capital costs schedule approved by the SCPSC in November 2012, SCE&G’s estimated cost would be approximately $500 million for the additional 5% interest being acquired from Santee Cooper. This cost figure is expected to be higher in light of the delays and related costs discussed above.

Nuclear Production Tax Credits

The IRS has 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. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion. Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on the above substantial completion dates provided by the Consortium of June 2019 and June 2020 for Units 2 and 3, respectively, both New Units are expected to be operational and to qualify for the nuclear production tax credits; however, further delays in the schedule or changes in tax law could impact such conclusions. To the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers as so realized.

Other Project Matters

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. SCE&G prepared and submitted an integrated response plan for the New Units to the NRC in August 2013. That plan is currently under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units.

Environmental

Consolidated SCE&G's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on Consolidated SCE&G's financial condition, results of operations and cash flows. In addition, Consolidated SCE&G often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, Consolidated SCE&G expects to recover such expenditures and costs through existing ratemaking provisions.

The EPA issued 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 proposed rule was issued 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 could be constructed without carbon capture and sequestration capabilities. Consolidated SCE&G is evaluating the proposed rule, but does not plan to construct new coal-fired units in the near future. In addition, on June 2, 2014, the EPA issued proposed emission guidelines for states to follow in developing plans to address GHG emissions from existing units. These guidelines are expected to be made final in late summer 2015, and include state-specific rate based goals for carbon dioxide emissions.

From a regulatory perspective, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in construction activities of the New Units which are expected to reduce GHG emission levels significantly once they are completed and dispatched by potentially displacing some of the current coal-fired generation sources. These actions are expected to address many of the rules and regulations discussed herein.

In July 2011, the EPA issued the CSAPR to reduce emissions of sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, thus delaying the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and annual or ozone season nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for sulfur dioxide and nitrogen oxide and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the allowances set by the CSAPR.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective.  The rule provides up to four years for generating facilities to meet the standards, and SCE&G and GENCO's evaluation of the rule is ongoing. SCE&G's decision 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 SCE&G's compliance with MATS. On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities. SCE&G and GENCO have received a one year extension (until April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions will allow time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants that will enhance the control of certain MATS-regulated pollutants.

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 no later than September 30, 2015. Once the rule becomes effective, state regulators will modify facility NPDES permits to match more restrictive standards, thus requiring facilities to retrofit with new wastewater treatment technologies. Compliance dates will vary by type of wastewater, and some will be based on a facility's five year permit cycle and thus may range from 2018 to 2023. Based on the proposed rule, Consolidated SCE&G expects that wastewater treatment technology retrofits will be required at Williams and Wateree Stations and may be required at other facilities.

The CWA Section 316(b) Existing Facilities Rule became effective on October 14, 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans to ensure compliance with this rule. In addition, Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones.

On April 17, 2015, the EPA's final rule for CCR was published in the Federal Register and will become effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act. In addition, this rule imposes certain requirements on ash storage ponds at SCE&G's and GENCO's generating facilities. While this rule is still being evaluated, SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds.

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. As of December 31, 2014, 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.

The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The state of South Carolina has similar laws. SCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify 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 by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA.  SCE&G anticipates that major remediation activities at all these sites will continue at least through 2017 and will cost an additional $19.2 million, which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.  At March 31, 2015, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $35.2 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
	Mar. 31, 2015	Mar. 31, 2014
Operating Revenues:
Electric Domestic Regulated Revenue	$ 629	$ 678
Regulated Operating Revenue, Gas	369	458
Gas-nonregulated	391	454
Regulated and Unregulated Operating Revenue	1,389	1,590
Operating Expenses [Abstract]
Fuel used in electric generation	174	212
Purchased power	13	25
Gas purchased for resale	523	670
Other operation and maintenance	173	180
Depreciation and amortization	96	95
Other taxes	59	58
Total Operating Expenses	1,038	1,240
Gain (Loss) on Disposition of Business	235	0
Operating Income	586	350
Other Income (Expense):
Other income	19	15
Other expenses	(12)	(14)
Gain (Loss) On Disposition Of Unregulated Business Net Of Transaction Costs	107	0
Interest Expense	(77)	(76)
Allowance for equity funds used during construction	5	7
Total Other Expense	42	(68)
Income Before Income Tax Expense	628	282
Income Tax Expense	228	89
Net Income	400	193
Per Common Share Data
Basic Earnings Per Share of Common Stock (in dollars per share)	$ 2.8	$ 1.37
Weighted Average Number of Shares Outstanding, Basic and Diluted	142.9	141.1
Common Stock, Dividends, Per Share, Declared	$ 0.5450	$ 0.5250
SCEG
Operating Revenues:
Electric Domestic Regulated Revenue	630	680
Regulated Operating Revenue, Gas	142	179
Regulated Operating Revenue	772	859
Operating Expenses [Abstract]
Fuel used in electric generation	174	214
Purchased power	13	25
Gas purchased for resale	74	109
Other operation and maintenance	139	142
Depreciation and amortization	80	78
Other taxes	55	52
Total Operating Expenses	535	620
Operating Income	237	239
Other Income (Expense):
Other income	9	3
Other expenses	(8)	(6)
Interest Expense	(59)	(56)
Allowance for equity funds used during construction	5	5
Total Other Expense	(53)	(54)
Income Before Income Tax Expense	184	185
Income Tax Expense	58	59
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	126	126
Net Income (Loss) Attributable to Noncontrolling Interest	(4)	(3)
Earnings Available to Common Shareholder	122	123
Per Common Share Data
Dividends, Common Stock, Cash	$ 71	$ 64

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COMMON EQUITY

3 Months Ended

Mar. 31, 2015

Schedule of Capitalization, Equity [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

Changes in common equity during the three months ended March 31, 2015 and 2014 were as follows:

	Common Stock						Accumulated Other Comprehensive Income (Loss)
Millions	Shares	Amount		Retained Earnings			Gains(Losses) on Cash Flow Hedges			Deferred Employee Benefit Plans			Total AOCI			Total Common Equity
Balance as of January 1, 2015	143	$	2,378	$	2,684		$	(63	)	$	(12	)	$	(75	)	$	4,987
Net Income				400												400
Other Comprehensive Income (Loss):
Losses arising during the period							(3		)	(4		)	(7		)	(7		)
Gains/amortization reclassified from AOCI							9			—			9			9
Total Comprehensive Income (Loss)				400			6			(4		)	2			402
Issuance of Common Stock	—	14														14
Dividends Declared				(78		)										(78		)
Balance as of March 31, 2015	143	$	2,392	$	3,006		$	(57	)	$	(16	)	$	(73	)	$	5,325
Balance as of January 1, 2014	141	$	2,280	$	2,444		$	(52	)	$	(8	)	$	(60	)	$	4,664
Net Income				193												193
Other Comprehensive Income:
Gains arising during the period							1			—			1			1
Losses/amortization reclassified from AOCI							(2		)	—			(2		)	(2		)
Total Comprehensive Income				193			(1		)	—			(1		)	192
Issuance of Common Stock	—	27														27
Dividends Declared				(74		)										(74		)
Balance as of March 31, 2014	141	$	2,307	$	2,563		$	(53	)	$	(8	)	$	(61	)	$	4,809

Gains and losses on cash flow hedges reclassified during the three months ended March 31, 2015 resulted in higher interest expense of $2 million and higher cost of gas purchased for resale of $7 million. Such reclassifications during the comparable period in 2014 resulted in higher interest expense of $2 million and lower cost of gas purchased for resale of $4 million.

SCANA had 200 million shares of common stock authorized as of March 31, 2015 and December 31, 2014.

SCEG

Schedule of Capitalization, Equity [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

EQUITY

Changes in common equity during the three months ended March 31, 2015 and 2014 were as follows:

	Common Stock				Retained			Accumulated Other Comprehensive			Noncontrolling			Total
Millions	Shares	Amount			Earnings			Income (Loss)			Interest			Equity
Balance at January 1, 2015	40	$	2,560		$	2,077		$	(3	)	$	123		$	4,757
Earnings available to common shareholder					122						4			126
Deferred cost of employee benefit plans								—						—
Total Comprehensive Income					122			—			4			126
Capital returned to parent		(4		)										(4		)
Cash dividend declared					(69		)				(1		)	(70		)
Balance at March 31, 2015	40	$	2,556		$	2,130		$	(3	)	$	126		$	4,809
Balance at January 1, 2014	40	$	2,479		$	1,896		$	(3	)	$	117		$	4,489
Earnings available to common shareholder					123						3			126
Deferred cost of employee benefit plans								—						—
Total Comprehensive Income					123			—			3			126
Capital contributions from parent		20												20
Cash dividend declared					(62		)				(2		)	(64		)
Balance at March 31, 2014	40	$	2,499		$	1,957		$	(3	)	$	118		$	4,571

SCE&G had 50 million shares of common stock authorized as of March 31, 2015 and December 31, 2014. SCE&G had 20 million shares of preferred stock authorized as of March 31, 2015 and December 31, 2014, 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

3 Months Ended

Mar. 31, 2015

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 base 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 base fuel cost increase was offset by a reduction in SCE&G's rate rider related to pension costs, which was approved by the SCPSC in March 2014. In addition, pursuant to the April 29, 2014 order, the Company's electric revenue for 2014 was reduced by approximately $46 million for adjustments to the fuel cost component and related under-collected fuel balance. Such adjustments are fully offset by the recognition within other income of gains realized from the late 2013 settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. The order also provided for 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. See also Note 6.

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. The impact of changes to the Nuclear Waste Act fee is considered during annual fuel rate proceedings.

By order dated April 30, 2015, the SCPSC approved a settlement agreement among SCE&G, the ORS, and the SCEUC in which SCE&G agreed to decrease the total fuel cost component of retail electric rates. Under this order, SCE&G is to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2015, which is estimated to be $36.1 million, over a 12-month period beginning with the first billing cycle of May 2015.

On February 9, 2015, SCE&G petitioned the SCPSC for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. SCE&G's DER program is structured to achieve, no later than December 31, 2020, renewable energy facilities within South Carolina with an aggregate amount of installed nameplate generating capacity equal to at least two percent of the previous five-year average of SCE&G's retail peak demand. A public hearing on this matter has been scheduled to begin on June 2, 2015.     

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, and $1.9 million and $1.2 million of such carrying costs were accrued within other income during each of the three months ended March 31, 2015 and 2014, respectively. 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 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 a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G previously identified six coal-fired units that it has subsequently retired or intends to retire by 2020, subject to future developments in environmental regulations, among other matters. Three of these units were retired by December 31, 2013, and their net carrying value 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. The net carrying value of the remaining units is included in Plant to be Retired, Net. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.

SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and net lost 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 revenues, program costs, incentives and net program benefits. The SCPSC approved recovery of the following amounts pursuant to annual DSM Programs filings, which went into effect as indicated below:

Year	Effective	Amount
2015	First billing cycle of May	$32.0 million
2014	First billing cycle of May	$15.4 million
2013	First billing cycle of May	$16.9 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 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 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 revenues as of April 30, 2014, which had been deferred within regulatory assets resulting from the May 2013 order. 

• In addition, in April 2014 the SCPSC, upon recommendation of the ORS, reduced by 25%, or $6.6 million, the amount of net lost 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 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 recovery of the following amounts under the BLRA effective for bills rendered on and after October 30 in the following years:

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

On March 12, 2015, SCE&G petitioned the SCPSC seeking approval of an updated construction milestone schedule and capital cost schedule for the New Units. The updated construction schedule reflects new substantial completion dates for Units 2 and 3 of June 2019, and June 2020, respectively. The petition also incorporates in the construction cost schedules approximately $698 million (SCE&G’s portion in 2007 dollars) in incremental capital costs that have been identified since the last approved order in November 2012, of which $539 million (SCE&G’s portion in 2007 dollars) are associated with construction delays and other contested costs. The total project capital cost is now estimated at approximately $5.2 billion (SCE&G’s portion in 2007 dollars) or $6.8 billion including escalation and allowance for funds used during construction (SCE&G’s portion in future dollars). As noted in the petition, the construction and capital cost schedules are subject to continuing review and negotiations by the parties. In making this filing, SCE&G does not waive any claims related to delay and other related contested costs with the Consortium. A public hearing on this matter is scheduled to begin on July 21, 2015, and the SCPSC is expected to issue its order in September 2015. See Note 9.

In May 2015, SCE&G expects to file an application to recover through revised rates the financing cost of incremental construction work in progress incurred for new nuclear generation since the last rate action described above.  Any additional financing cost recovery approved by the SCPSC would be expected to  be effective for bills rendered on and after October 30, 2015.  It is expected that such rate action would be contingent upon a favorable SCPSC order on the March 2015 petition.

Gas

SCE&G

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

Year	Action			Amount
2014	0.6	%	Decrease	$2.6 million
2013	No change			-

SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. 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, 2014 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.

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.

In May 2014, the NCUC issued an order requiring utilities to adjust rates to reflect changes in the state corporate income tax rate that had been enacted by the North Carolina legislature and to file a proposal to refund amounts previously collected on a provisional basis. Pursuant to the order, PSNC Energy lowered its rates effective July 1, 2014, and refunded the amounts collected on a provisional basis through the normal operation of its Rider D rate mechanism. These amounts were not significant for any period presented.

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	March 31, 2015		December 31, 2014
Regulatory Assets:
Accumulated deferred income taxes	$	282	$	284
Under-collections - electric fuel adjustment clause	4		20
Environmental remediation costs	40		40
AROs and related funding	370		366
Franchise agreements	25		26
Deferred employee benefit plan costs	337		350
Planned major maintenance	—		2
Deferred losses on interest rate derivatives	549		453
Deferred pollution control costs	35		36
Unrecovered plant	132		137
DSM Programs	58		56
Carrying costs on deferred tax assets related to nuclear construction	11		9
Pipeline integrity management costs	10		9
Other	37		35
Total Regulatory Assets	$	1,890	$	1,823

Regulatory Liabilities:
Accumulated deferred income taxes	$	22	$	22
Asset removal costs	712		703
Storm damage reserve	6		6
Deferred gains on interest rate derivatives	82		82
Planned major maintenance	7		—
Other	—		1
Total Regulatory Liabilities	$	829	$	814

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 which are expected to be recovered in retail electric rates over periods exceeding 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 25 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 and distribution 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 2020.

Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. Accordingly, in 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations 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, 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 through 2043. 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.

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 2015 SCPSC order, deferred costs are currently being recovered over approximately five years through an approved rate rider. 

Carrying costs on deferred tax assets related to nuclear construction represent accrued carrying costs on accumulated deferred income tax assets associated with the New Units which are not part of electric base rates. These carrying costs are computed using weighted average debt cost of capital and will be amortized over ten years beginning in approximately 2021.

Pipeline integrity management costs represent costs incurred to comply with regulatory requirements related to certain natural gas pipelines located near moderate to high density populations. Such costs will be considered for recovery through rates in PSNC Energy's next general rate proceeding.

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

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

The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely. During the first quarter of 2015, no amounts were applied to offset incremental storm damage costs.

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 specifically 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. 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 base 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 base fuel cost increase was offset by a reduction in SCE&G's rate rider related to pension costs, which was approved by the SCPSC in March 2014. In addition, pursuant to the April 29, 2014 order, SCE&G's electric revenue for 2014 was reduced by approximately $46 million for adjustments to the fuel cost component and related under-collected fuel balance. Such adjustments are fully offset by the recognition within other income of gains realized from the late 2013 settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. The order also provided for 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. See also Note 6.

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. The impact of changes to the Nuclear Waste Act fee is considered during annual fuel rate proceedings.

By order dated April 30, 2015, the SCPSC approved a settlement agreement among SCE&G, the ORS, and the SCEUC in which SCE&G agreed to decrease the total fuel cost component of its retail electric rates. Under this order, SCE&G is to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2015, which is estimated to be $36.1 million, over a 12-month period beginning with the first billing cycle of May 2015.

On February 9, 2015, SCE&G petitioned the SCPSC for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. SCE&G's DER program is structured to achieve, no later than December 31, 2020, renewable energy facilities within South Carolina with an aggregate amount of installed nameplate generating capacity equal to at least two percent of the previous five-year average of SCE&G's retail peak demand. A public hearing on this matter has been scheduled to begin on June 2, 2015.

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, and $1.9 million and $1.2 million of such carrying costs were accrued within other income during each of the three months ended March 31, 2015 and 2014, respectively. 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 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 a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G previously identified six coal-fired units that it has subsequently retired or intends to retire by 2020, subject to future developments in environmental regulations, among other matters. Three of these units were retired by December 31, 2013, and their net carrying value 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. The net carrying value of the remaining units is included in Plant to be Retired, Net. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.

SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and net lost 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 revenues, program costs, incentives and net program benefits. The SCPSC approved recovery of the following amounts pursuant to annual DSM Programs filings, which went into effect as indicated below:

Year	Effective	Amount
2015	First billing cycle of May	$32.0 million
2014	First billing cycle of May	$15.4 million
2013	First billing cycle of May	$16.9 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 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 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 revenues as of April 30, 2014, which had been deferred within regulatory assets resulting from the May 2013 order. 

• In addition, in April 2014 the SCPSC, upon recommendation of the ORS, reduced by 25%, or $6.6 million, the amount of net lost 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 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 recovery of the following amounts under the BLRA effective for bills rendered on and after October 30 in the following years:

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

On March 12, 2015, SCE&G petitioned the SCPSC seeking approval of an updated construction milestone schedule and capital cost schedule for the New Units. The updated construction schedule reflects new substantial completion dates for Units 2 and 3 of June 2019, and June 2020, respectively. The petition also incorporates in the construction cost schedules approximately $698 million (SCE&G’s portion in 2007 dollars) in incremental capital costs that have been identified since the last approved order in November 2012, of which $539 million (SCE&G’s portion in 2007 dollars) are associated with construction delays and other contested costs. The total project capital cost is now estimated at approximately $5.2 billion (SCE&G’s portion in 2007 dollars) or $6.8 billion including escalation and allowance for funds used during construction (SCE&G’s portion in future dollars). As noted in the petition, the construction and capital cost schedules are subject to continuing review and negotiations by the parties. In making this filing, SCE&G does not waive any claims related to delay and other related contested costs with the Consortium. A public hearing on this matter is scheduled to begin on July 21, 2015, and the SCPSC is expected to issue its order in September 2015. See Note 9.

In May 2015, SCE&G expects to file an application to recover through revised rates the financing cost of incremental construction work in progress incurred for new nuclear generation since the last rate action described above.  Any additional financing cost recovery approved by the SCPSC would be expected to  be effective for bills rendered on and after October 30, 2015.  It is expected that such rate action would be contingent upon a favorable SCPSC order on the March 2015 petition.

Gas

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

Year	Action			Amount
2014	0.6	%	Decrease	$2.6 million
2013	No change			-

SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. 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, 2014 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.

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	March 31, 2015		December 31, 2014
Regulatory Assets:
Accumulated deferred income taxes	$	276	$	278
Under collections – electric fuel adjustment clause	4		20
Environmental remediation costs	35		36
AROs and related funding	350		347
Franchise agreements	25		26
Deferred employee benefit plan costs	305		310
Planned major maintenance	—		2
Deferred losses on interest rate derivatives	549		453
Deferred pollution control costs	35		36
Unrecovered plant	132		137
DSM Programs	58		56
Carrying costs on deferred tax assets related to nuclear construction	11		9
Other	37		35
Total Regulatory Assets	$	1,817	$	1,745

Regulatory Liabilities:
Accumulated deferred income taxes	$	16	$	17
Asset removal costs	510		505
Storm damage reserve	6		6
Deferred gains on interest rate derivatives	82		82
Planned major maintenance	7		—
Total Regulatory Liabilities	$	621	$	610

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 which are expected to be recovered in retail electric rates over periods exceeding 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 25 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 and distribution 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 2020.

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 pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. Accordingly, in 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations 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, 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 through 2043. 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.

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 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 2015 SCPSC order, deferred costs are currently being recovered over approximately five years through an approved rate rider. 

Carrying costs on deferred tax assets related to nuclear construction represent accrued carrying costs on accumulated deferred income tax assets associated with the New Units which are not part of electric base rates. These carrying costs are computed using weighted average debt cost of capital and will be amortized over ten years beginning in approximately 2021.

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

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

The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely. During the first quarter of 2015, no amounts were applied to offset incremental storm damage costs.

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 specifically approved for recovery by the SCPSC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by SCE&G. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, Consolidated SCE&G could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on Consolidated SCE&G's results of operations, liquidity or financial position in the period the write-off would be recorded.

XML

RATE AND OTHER REGULATORY MATTERS (Tables)

3 Months Ended

Mar. 31, 2015

Regulatory Assets

Demand reduction programs [Table Text Block]

:

Year	Effective	Amount
2015	First billing cycle of May	$32.0 million
2014	First billing cycle of May	$15.4 million
2013	First billing cycle of May	$16.9 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

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

Year	Action			Amount
2014	0.6	%	Decrease	$2.6 million
2013	No change			-

Schedule of Regulatory Assets [Table Text Block]

.

Millions of dollars	March 31, 2015		December 31, 2014
Regulatory Assets:
Accumulated deferred income taxes	$	282	$	284
Under-collections - electric fuel adjustment clause	4		20
Environmental remediation costs	40		40
AROs and related funding	370		366
Franchise agreements	25		26
Deferred employee benefit plan costs	337		350
Planned major maintenance	—		2
Deferred losses on interest rate derivatives	549		453
Deferred pollution control costs	35		36
Unrecovered plant	132		137
DSM Programs	58		56
Carrying costs on deferred tax assets related to nuclear construction	11		9
Pipeline integrity management costs	10		9
Other	37		35
Total Regulatory Assets	$	1,890	$	1,823

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Accumulated deferred income taxes	$	22	$	22
Asset removal costs	712		703
Storm damage reserve	6		6
Deferred gains on interest rate derivatives	82		82
Planned major maintenance	7		—
Other	—		1
Total Regulatory Liabilities	$	829	$	814

SCEG

Regulatory Assets

Demand reduction programs [Table Text Block]

Year	Effective	Amount
2015	First billing cycle of May	$32.0 million
2014	First billing cycle of May	$15.4 million
2013	First billing cycle of May	$16.9 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

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

Year	Action			Amount
2014	0.6	%	Decrease	$2.6 million
2013	No change			-

Schedule of Regulatory Assets [Table Text Block]

Millions of dollars	March 31, 2015		December 31, 2014
Regulatory Assets:
Accumulated deferred income taxes	$	276	$	278
Under collections – electric fuel adjustment clause	4		20
Environmental remediation costs	35		36
AROs and related funding	350		347
Franchise agreements	25		26
Deferred employee benefit plan costs	305		310
Planned major maintenance	—		2
Deferred losses on interest rate derivatives	549		453
Deferred pollution control costs	35		36
Unrecovered plant	132		137
DSM Programs	58		56
Carrying costs on deferred tax assets related to nuclear construction	11		9
Other	37		35
Total Regulatory Assets	$	1,817	$	1,745

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Accumulated deferred income taxes	$	16	$	17
Asset removal costs	510		505
Storm damage reserve	6		6
Deferred gains on interest rate derivatives	82		82
Planned major maintenance	7		—
Total Regulatory Liabilities	$	621	$	610

XML

SEGMENT OF BUSINESS INFORMATION

3 Months Ended

Mar. 31, 2015

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 the parent company, a services company and other nonreportable segments that were insignificant for all periods presented. In addition, All Other includes gains from the sales of CGT and SCI (see Note 11) and their operating results and assets prior to their sale in the first quarter of 2015. CGT and SCI were nonreportable segments during all periods presented. For the period ended March 31, 2015, operating income and net income for All Other include $235 million and $202 million, respectively, related to the sales of CGT and SCI. External revenue and intersegment revenue for All Other related to CGT and SCI were not significant during any period presented.

Millions of dollars	External Revenue			Intersegment Revenue			Operating Income		Net Income
Three Months Ended March 31, 2015
Electric Operations	$	629		—			$	199	n/a
Gas Distribution	368			—			96		n/a
Retail Gas Marketing	204			—			n/a		$	27
Energy Marketing	187			$	35		n/a		6
All Other	4			114			238		207
Adjustments/Eliminations	(3		)	(149		)	53		160
Consolidated Total	$	1,389		$	—		$	586	$	400

Three Months Ended March 31, 2014
Electric Operations	$	678		$	2		$	198	n/a
Gas Distribution	455			—			97		n/a
Retail Gas Marketing	220			—			n/a		$	22
Energy Marketing	234			53			n/a		7
All Other	9			110			8		4
Adjustments/Eliminations	(6		)	(165		)	47		160
Consolidated Total	$	1,590		$	—		$	350	$	193

	March 31,		December 31,
Segment Assets	2015		2014
Electric Operations	$	10,300	$	10,182
Gas Distribution	2,504		2,487
Retail Gas Marketing	155		140
Energy Marketing	128		150
All Other	1,494		1,474
Adjustments/Eliminations	1,825		2,419
Consolidated Total	$	16,406	$	16,852

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.

Millions of dollars	External Revenue		Operating Income		Earnings Available to Common Shareholder
Three Months Ended March 31, 2015
Electric Operations	$	630	$	199	n/a
Gas Distribution	142		38		n/a
Adjustments/Eliminations	—		—		$	122
Consolidated Total	$	772	$	237	$	122

Three Months Ended March 31, 2014
Electric Operations	$	680	$	198	n/a
Gas Distribution	179		41		n/a
Adjustments/Eliminations	—		—		$	123
Consolidated Total	$	859	$	239	$	123

Segment Assets	March 31, 2015		December 31, 2014
Electric Operations	$	10,300	$	10,182
Gas Distribution	731		721
Adjustments/Eliminations	3,103		3,204
Consolidated Total	$	14,134	$	14,107

XML

DERIVATIVE FINANCIAL INSTRUMENTS

3 Months Ended

Mar. 31, 2015

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 their 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 not designated as cash flow hedges, and all related fair value changes and settlement amounts are recorded as regulatory assets or liabilities. Interest rate derivatives entered into before October 2013 were designated as cash flow hedges, and for such instruments only the effective portion of fair value changes and settlement amounts are recorded in regulatory assets or regulatory liabilities. Upon settlement, losses on swaps are amortized over the lives of related debt issuances, and gains are applied to under-collected fuel, are amortized to interest expense or are 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 March 31, 2015
Commodity contracts	10,140,000	5,633,000	3,528,964	19,301,964
Energy management contracts (a)	—	—	40,811,533	40,811,533
Total (a)	10,140,000	5,633,000	44,340,497	60,113,497
As of December 31, 2014
Commodity contracts	6,840,000	7,951,000	3,446,720	18,237,720
Energy management contracts (b)	—	—	37,495,339	37,495,339
Total (b)	6,840,000	7,951,000	40,942,059	55,733,059

(a)  Includes an aggregate 3,148,404 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 933,893 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 March 31, 2015 and $124.4 million at December 31, 2014. The Company was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.3 billion at March 31, 2015 and $1.1 billion at December 31, 2014.

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

Fair Values of Derivative Instruments	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
Millions of dollars	Location	Value		Location	Value
As of March 31, 2015
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	4
				Other deferred credits and other liabilities	33
Commodity contracts				Other current assets	1
				Derivative financial instruments	4
Total					$	42
Not designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	288
				Other deferred credits and other liabilities	30
Commodity contracts	Other current assets	$	1
Energy management contracts	Other current assets	13		Other current assets	3
				Derivative financial instruments	10
	Other deferred debits and other assets	6		Other deferred credits and other liabilities	6
Total		$	20		$	337

As of December 31, 2014
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	5
				Other deferred credits and other liabilities	28
Commodity contracts				Other current assets	1
				Derivative financial instruments	11
Total					$	45
Not designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	207
				Other deferred credits and other liabilities	17
Commodity contracts	Other current assets	$	1
Energy management contracts	Other current assets	15		Other current assets	5
				Derivative financial instruments	10
	Other deferred debits and other assets	5		Other deferred credits and other liabilities	5
Total		$	21		$	244

 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

	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2015			2014			Location	2015	2014
Three Months Ended March 31,
Interest rate contracts	$	(2	)	$	(3	)	Interest expense	—	$	(1	)

	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	2015			2014			Location	2015			2014
Three Months Ended March 31,
Interest rate contracts	$	(2	)	$	(2	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	(1		)	3			Gas purchased for resale	(7		)	4
Total	$	(3	)	$	1			$	(9	)	$	2

As of March 31, 2015, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive income (loss) to earnings arising from cash flow hedges will include approximately $4.0 million as an increase to gas cost and approximately $6.4 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of March 31, 2015, all of the Company’s commodity cash flow hedges settle by their terms before the end of the first quarter of 2017.

As of March 31, 2015, the Company expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.3 million as an increase to interest expense, assuming financial markets remain at their current levels.

Hedge Ineffectiveness

Other losses recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in the three months ended March 31, 2015 and 2014, respectively.

Derivatives not designated as Hedging Instruments
	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2015			2014			Location	2015		2014
Three Months Ended March 31,
Interest rate contracts	$	(94	)	$	(112	)	Other income	$	4	—

As of March 31, 2015, 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 $0.7 million as an increase to other income.

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 March 31, 2015 and December 31, 2014, the Company has posted $233.5 million and $152.4 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 March 31, 2015 and December 31, 2014, the Company could have been required to post an additional $141.7 million and $129.8 million, respectively, of collateral with its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of March 31, 2015 and December 31, 2014 is $375.2 million and $282.2 million, respectively.

As noted previously, for all periods presented, the Company did not have interest rate derivative instruments in a net asset position and did not have commodity derivatives with underlying contingent features which, if triggered, would have permitted the Company to request collateral from its counterparties. At March 31, 2015, the Company could have called on letters of credit in the amount of $3.0 million related to $19.0 million in commodity derivatives that are in a net asset position, compared to letters of credit of $9.2 million related to derivatives of $20.0 million at December 31, 2014, 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 of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position		Net Amount
Millions of dollars						Financial Instruments	Cash Collateral Received
As of March 31, 2015
Commodity contracts	$	1	—	$	1	—	—	$	1
Energy management contracts	19		—	19		—	—	19
Total	$	20	—	$	20	—	—	$	20
Balance sheet location	Other current assets			$	14
	Other deferred debits and other assets			6
	Total			$	20

As of December 31, 2014
Commodity contracts	$	1	—	$	1	—	—	$	1
Energy management contracts	20		—	20		—	—	20
Total	$	21	—	$	21	—	—	$	21
Balance sheet location	Other current assets			$	16
	Other deferred debits and other assets			5
	Total			$	21

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

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position				Net Amount
Millions of dollars						Financial Instruments	Cash Collateral Posted
As of March 31, 2015
Interest rate contracts	$	355	—	$	355	—	$	(216	)	$	139
Commodity contracts	5		—	5		—	(4		)	1
Energy management contracts	19		—	19		—	(13		)	6
Total	$	379	—	$	379	—	$	(233	)	$	146
Balance sheet location	Other current assets			$	4
	Derivative financial instruments			306
	Other deferred credits and other liabilities			69
	Total			$	379

As of December 31, 2014
Interest rate contracts	$	257	—	$	257	—	$	(131	)	$	126
Commodity contracts	12		—	12		—	(10		)	2
Energy management contracts	20		—	20		—	(11		)	9
Total	$	289	—	$	289	—	$	(152	)	$	137
Balance sheet location	Other current assets			$	6
	Derivative financial instruments			233
	Other deferred credits and other liabilities			50
	Total			$	289

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 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 their 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 not designated as cash flow hedges, and all related fair value changes and settlement amounts are recorded as regulatory assets or liabilities. Interest rate derivatives entered into before October 2013 were designated as cash flow hedges, and for such instruments only the effective portion of fair value changes and settlement amounts are recorded in regulatory assets or regulatory liabilities. Upon settlement, losses on swaps are amortized over the lives of related debt issuances, and gains are applied to under-collected fuel, are amortized to interest expense or are 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

GENCO was party to an interest rate swap designated as a cash flow hedge with a notional amount of $36.4 million at March 31, 2015 and $36.4 million at December 31, 2014. SCE&G was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.3 billion at March 31, 2015 and $1.1 billion at December 31, 2014, respectively.

The fair value of interest rate derivatives (each of which was a liability derivative for all periods presented) was reflected in the condensed consolidated balance sheet as follows:

Fair Values of Derivative Instruments	Liability Derivatives
	Balance Sheet	Fair
Millions of dollars	Location	Value
As of March 31, 2015
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	1
	Other deferred credits and other liabilities	10
Total		$	11
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	288
	Other deferred credits and other liabilities	30
Total		$	318
As of December 31, 2014
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	1
	Other deferred credits and other liabilities	8
Total		$	9
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	207
	Other deferred credits and other liabilities	17
Total		$	224

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

Derivatives in Cash Flow Hedging Relationships	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2015			2014			Location	2015	2014
Three Months Ended March 31,
Interest rate contracts	$	(2	)	$	(3	)	Interest expense	—	$	(1	)

As of March 31, 2015, Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.3 million as an increase to interest expense, assuming financial markets remain at their current levels.

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 ended March 31, 2015 and 2014, respectively.

Derivatives not designated as Hedging Instruments	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2015			2014			Location	2015		2014
Three Months Ended March 31,
Interest rate contracts	$	(94	)	$	(112	)	Other income	$	4	—

As of March 31, 2015, 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 $0.7 million as an increase to other income.

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 March 31, 2015 and December 31, 2014, Consolidated SCE&G has posted $188.6 million and $107.1 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 March 31, 2015 and December 31, 2014, Consolidated SCE&G could have been required to post an additional $140.7 million and $125.9 million, respectively, of collateral with its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of March 31, 2015 and December 31, 2014 is $329.3 million and $233.0 million, respectively.

As noted previously, Consolidated SCE&G did not have interest rate derivatives in a net asset position for any period presented.

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

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position				Net Amount
Millions of dollars						Financial Instruments	Cash Collateral Posted
As of March 31, 2015
Interest rate contracts	$	329	—	$	329	—	$	(189	)	$	140
Balance Sheet Location	Derivative financial instruments			$	289
	Other deferred credits and other liabilities			40
	Total			$	329

As of December 31, 2014
Interest rate contracts	$	233	—	$	233	—	$	(107	)	$	126
Balance Sheet Location	Derivative financial instruments			$	208
	Other deferred credits and other liabilities			25
				$	233

XML

LONG-TERM AND SHORT-TERM DEBT

3 Months Ended

Mar. 31, 2015

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.

On February 2, 2015, SCANA redeemed prior to maturity $150 million of its 7.7% junior subordinated notes at their face value.

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	March 31, 2015			December 31, 2014			March 31, 2015			December 31, 2014			March 31, 2015		December 31, 2014
Lines of credit:
Total committed long-term	$	300		$	300		$	1,400		$	1,400		$	100	$	100
Outstanding commercial paper (270 or fewer days)	$	15		$	179		$	610		$	709		—		30
Weighted average interest rate	0.65		%	0.54		%	0.54		%	0.52		%	—		0.65		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—		—
Available	$	282		$	118		$	790		$	691		$	100	$	70

SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million, $1.2 billion (of which $500 million relates to Fuel Company) and $100 million, respectively, which expire in October 2019. In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million, which 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 TD Bank N.A. These letters of credit expire, subject to renewal, in the fourth quarter of 2019.

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.

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	March 31, 2015			December 31, 2014
Lines of credit:
Total committed long-term	$	1,400		$	1,400
Outstanding commercial paper (270 or fewer days)	$	610		$	709
Weighted average interest rate	0.54		%	0.52		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	790		$	691

SCE&G and Fuel Company are parties to five-year credit agreements in the amount of $1.2 billion (of which $500 million relates to Fuel Company), which expire in October 2019. In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million, which 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 TD Bank N.A. These letters of credit expire, subject to renewal, in the fourth quarter of 2019.

Consolidated SCE&G participates in a utility money pool with SCANA and certain other subsidiaries of SCANA. 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 March 31, 2015, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $275.5 million. At December 31, 2014, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $83.0 million and money pool investments due from an affiliate of $80.0 million.

XML

INCOME TAXES

3 Months Ended

Mar. 31, 2015

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

During 2013 and 2014, 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 $16 million. If recognized, $13 million of the tax benefit would affect the Company’s effective tax rate. It is reasonably possible that this tax benefit will increase by an additional $2 million within the next 12 months. It is also reasonably possible that this tax benefit may decrease by $7 million within the next 12 months. No other material changes in the status of the Company’s tax positions have occurred through March 31, 2015.

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.

SCEG

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

During 2013 and 2014, SCANA amended certain of its 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 $16 million. If recognized, $13 million of the tax benefit would affect Consolidated SCE&G’s effective tax rate. It is reasonably possible that this tax benefit will increase by an additional $2 million within the next 12 months. It is also reasonably possible that this tax benefit may decrease by $7 million within the next 12 months. No other material changes in the status of Consolidated SCE&G’s tax positions have occurred through March 31, 2015.

                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.

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

3 Months Ended

Mar. 31, 2015

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 March 31, 2015				As of December 31, 2014
Millions of dollars	Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	$	13	—		$	13	—
Commodity contracts	1		—		1		—
Energy management contracts	—		$	19	—		$	20
Liabilities:
Interest rate contracts	—		355		—		257
Commodity contracts	—		—		1		11
Energy management contracts	3		23		5		18

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 were as follows:

	March 31, 2015				December 31, 2014
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	5,541.6	$	6,501.6	$	5,697.2	$	6,592.1

Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates.  As such, the aggregate fair values presented above are considered to be Level 2. 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.  These fair values are considered to be Level 2. The fair value of derivative liabilities were $329 million at March 31, 2015 and $233 million at December 31, 2014. Consolidated SCE&G did not have derivative assets for any period presented.

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 were as follows:

	March 31, 2015				December 31, 2014
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,303.3	$	5,119.2	$	4,308.6	$	5,070.9

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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RATE AND OTHER REGULATORY MATTERS (Details 3) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Mar. 31, 2014	Mar. 31, 2013
Regulatory Liabilities [Line Items]
Regulatory Assets, Noncurrent	$ 1,890.0	$ 1,823.0
Regulatory Liabilities	829	814
SCEG
Regulatory Liabilities [Line Items]
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates		0.60%
Regulatory Assets, Noncurrent	1,817.0	1,745.0
Public Utilities Increase (Decrease) in Retail Electric Rates Approved under BLRA		66.2	67.2
Public Utilities, Authorized Allowable Return on Common Equity, Percentage	11.00%
Demand Side Management Program Costs, Noncurrent	32.0			15.4	16.9
Regulatory Liabilities	621	610
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	1.0
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	712	703
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	510	505
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	6
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	6
Deferred gains on interest rate derivatives [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	82	82
Deferred gains on interest rate derivatives [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	82	82
Deferred Income Tax Charges [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	22	22
Deferred Income Tax Charges [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	16	17
Planned major maintenance [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	7	0
Planned major maintenance [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 7	$ 0

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Dispositions (Notes)

3 Months Ended

Mar. 31, 2015

Disposal groups [Abstract]

Disposal Group, Held for Sale [Text Block]

DISPOSITIONS

In December 2014, SCANA entered into definitive agreements to sell CGT and SCI. CGT is an interstate natural gas pipeline regulated by FERC that transports natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provides fiber optic communications and other services and builds, manages and leases communications towers in several southeastern states, and it was sold to a subsidiary of Spirit Communications. These sales closed in the first quarter of 2015. The pre-tax gain on the sales recognized during the first quarter of 2015 was approximately $342 million. As further described in Note 1, the pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the consolidated income statement.

CGT and SCI operate principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. In addition, neither CGT nor SCI met accounting criteria for disclosure as a reportable segment and were included within All Other in Note 10. The sales of CGT and SCI did not represent a strategic shift that will have a major effect on SCANA's operations; therefore, these sales do not meet the criteria for classification as discontinued operations.

The carrying values of the major classes of assets and liabilities classified as held for sale in the consolidated balance sheet as of December 31, 2014, were as follows:

Millions of dollars	CGT		SCI		Total
Assets Held for Sale
Utility Plant, Net	$	288.4	—		$	288.4
Nonutility Property and Investments, Net	0.6		$	40.1	40.7
Current Assets	6.5		3.9		10.4
Deferred Debits and Other Assets	0.9		0.2		1.1
Total Assets Held for Sale	296.4		44.2		340.6
Liabilities Held for Sale
Current Liabilities	$	3.5	$	2.2	$	5.7
Deferred Credits and Other Liabilities	42.9		3.1		46.0
Total Liabilities Held for Sale	$	46.4	$	5.3	$	51.7

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DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

3 Months Ended

Mar. 31, 2015

Derivative [Line Items]

Schedule of Derivative Instruments [Table Text Block]

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

	Commodity and Other Energy Management Contracts (in MMBTU)
Hedge designation	Gas Distribution	Retail Gas Marketing	Energy Marketing	Total
As of March 31, 2015
Commodity contracts	10,140,000	5,633,000	3,528,964	19,301,964
Energy management contracts (a)	—	—	40,811,533	40,811,533
Total (a)	10,140,000	5,633,000	44,340,497	60,113,497
As of December 31, 2014
Commodity contracts	6,840,000	7,951,000	3,446,720	18,237,720
Energy management contracts (b)	—	—	37,495,339	37,495,339
Total (b)	6,840,000	7,951,000	40,942,059	55,733,059

(a)  Includes an aggregate 3,148,404 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 933,893 MMBTU related to basis swap contracts in Energy Marketing.

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

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

Fair Values of Derivative Instruments	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
Millions of dollars	Location	Value		Location	Value
As of March 31, 2015
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	4
				Other deferred credits and other liabilities	33
Commodity contracts				Other current assets	1
				Derivative financial instruments	4
Total					$	42
Not designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	288
				Other deferred credits and other liabilities	30
Commodity contracts	Other current assets	$	1
Energy management contracts	Other current assets	13		Other current assets	3
				Derivative financial instruments	10
	Other deferred debits and other assets	6		Other deferred credits and other liabilities	6
Total		$	20		$	337

As of December 31, 2014
Designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	5
				Other deferred credits and other liabilities	28
Commodity contracts				Other current assets	1
				Derivative financial instruments	11
Total					$	45
Not designated as hedging instruments
Interest rate contracts				Derivative financial instruments	$	207
				Other deferred credits and other liabilities	17
Commodity contracts	Other current assets	$	1
Energy management contracts	Other current assets	15		Other current assets	5
				Derivative financial instruments	10
	Other deferred debits and other assets	5		Other deferred credits and other liabilities	5
Total		$	21		$	244

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

Derivatives in Cash Flow Hedging Relationships

	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2015			2014			Location	2015	2014
Three Months Ended March 31,
Interest rate contracts	$	(2	)	$	(3	)	Interest expense	—	$	(1	)

	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	2015			2014			Location	2015			2014
Three Months Ended March 31,
Interest rate contracts	$	(2	)	$	(2	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	(1		)	3			Gas purchased for resale	(7		)	4
Total	$	(3	)	$	1			$	(9	)	$	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
	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2015			2014			Location	2015		2014
Three Months Ended March 31,
Interest rate contracts	$	(94	)	$	(112	)	Other income	$	4	—

Offseting Assets [Table Text Block]

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

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position		Net Amount
Millions of dollars						Financial Instruments	Cash Collateral Received
As of March 31, 2015
Commodity contracts	$	1	—	$	1	—	—	$	1
Energy management contracts	19		—	19		—	—	19
Total	$	20	—	$	20	—	—	$	20
Balance sheet location	Other current assets			$	14
	Other deferred debits and other assets			6
	Total			$	20

As of December 31, 2014
Commodity contracts	$	1	—	$	1	—	—	$	1
Energy management contracts	20		—	20		—	—	20
Total	$	21	—	$	21	—	—	$	21
Balance sheet location	Other current assets			$	16
	Other deferred debits and other assets			5
	Total			$	21

Offsetting Liabilities [Table Text Block]

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

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position				Net Amount
Millions of dollars						Financial Instruments	Cash Collateral Posted
As of March 31, 2015
Interest rate contracts	$	355	—	$	355	—	$	(216	)	$	139
Commodity contracts	5		—	5		—	(4		)	1
Energy management contracts	19		—	19		—	(13		)	6
Total	$	379	—	$	379	—	$	(233	)	$	146
Balance sheet location	Other current assets			$	4
	Derivative financial instruments			306
	Other deferred credits and other liabilities			69
	Total			$	379

As of December 31, 2014
Interest rate contracts	$	257	—	$	257	—	$	(131	)	$	126
Commodity contracts	12		—	12		—	(10		)	2
Energy management contracts	20		—	20		—	(11		)	9
Total	$	289	—	$	289	—	$	(152	)	$	137
Balance sheet location	Other current assets			$	6
	Derivative financial instruments			233
	Other deferred credits and other liabilities			50
	Total			$	289

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 (each of which was a liability derivative for all periods presented) was reflected in the condensed consolidated balance sheet as follows:

Fair Values of Derivative Instruments	Liability Derivatives
	Balance Sheet	Fair
Millions of dollars	Location	Value
As of March 31, 2015
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	1
	Other deferred credits and other liabilities	10
Total		$	11
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	288
	Other deferred credits and other liabilities	30
Total		$	318
As of December 31, 2014
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	1
	Other deferred credits and other liabilities	8
Total		$	9
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	207
	Other deferred credits and other liabilities	17
Total		$	224

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

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

Derivatives in Cash Flow Hedging Relationships	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2015			2014			Location	2015	2014
Three Months Ended March 31,
Interest rate contracts	$	(2	)	$	(3	)	Interest expense	—	$	(1	)

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

Derivatives not designated as Hedging Instruments	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2015			2014			Location	2015		2014
Three Months Ended March 31,
Interest rate contracts	$	(94	)	$	(112	)	Other income	$	4	—

Offsetting Liabilities [Table Text Block]

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

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position				Net Amount
Millions of dollars						Financial Instruments	Cash Collateral Posted
As of March 31, 2015
Interest rate contracts	$	329	—	$	329	—	$	(189	)	$	140
Balance Sheet Location	Derivative financial instruments			$	289
	Other deferred credits and other liabilities			40
	Total			$	329

As of December 31, 2014
Interest rate contracts	$	233	—	$	233	—	$	(107	)	$	126
Balance Sheet Location	Derivative financial instruments			$	208
	Other deferred credits and other liabilities			25
				$	233

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AFFILIATED TRANSACTIONS -SCEG (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Sep. 30, 2014
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	$ 69.7	$ 39.0
Due to Affiliate, Current	18.6		27.9
Due from Affiliate, Current	18.5		27.8
Equity Method Investment, Ownership Percentage	40.00%
CGT [Member]
Related Party Transaction [Line Items]
Related Party Transaction Purchases from Related Party	3.4	5.5
Due to Affiliate, Current			3.3
Due from Affiliate, Current			1.2	0
Energy Marketing [Member]
Related Party Transaction [Line Items]
Due to Affiliate, Current	10.6		12.6
Cost of Natural Gas Purchases	34.6	53.4
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Related Party Transaction Purchases from Related Party	70.1	39.2
SCANA Services [Member]
Related Party Transaction [Line Items]
Related Party Transaction Purchases from Related Party	48.4		47.3
Related Party Transaction, Expenses from Transactions with Related Party	$ 73.1	$ 76.2

XML

DERIVATIVE FINANCIAL INSTRUMENTS On Income Statement (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	$ (3)	$ (1)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	(9)	2
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant
Commodity Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	(1)	3
Interest Rate Contract [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	(2)	(2)
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(2)	(3)
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(94)	(112)
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	0.7
Other Nonoperating Income (Expense) [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	4	0
Gas Purchased for Resale [Member] [Member] | Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	4.0
Interest Expense [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	6.4
Interest Expense [Member] | Interest Rate Contract [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	0	(1)
Interest Expense [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	2.3
SCEG
Derivative [Line Items]
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant
SCEG | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(94)	(112)
SCEG | Other Nonoperating Income (Expense) [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	4	0
SCEG | Other Nonoperating Income (Expense) [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	0.7
SCEG | Interest Expense [Member] | Interest Rate Contract [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	0	(1)
SCEG | Interest Expense [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(2)	(3)
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	$ 2.3

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Allowance for Funds Used During Construction, Capitalized Interest	$ 3	$ 3
Earnings Per Share, Diluted	$ 2.80	$ 1.37
SCEG
Allowance for Funds Used During Construction, Capitalized Interest	$ 3	$ 3

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

Mar. 31, 2015

Significant Accounting Policies

Significant Accounting Policies [Text Block]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Plant to be Retired

SCE&G expects to retire three units that are or were coal-fired by 2020, subject to future developments in environmental regulations, among other matters. The net carrying value of these units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. The net carrying value of three previously retired units is recorded in regulatory assets within unrecovered plant (see Note 2).

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.  There were no securities considered to be dilutive potential common stock during any period presented. The Company has issued no securities that would have an antidilutive effect on earnings per share.

Asset Management and Supply Service Agreements

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities.  Such counterparties held 32% and 48% of PSNC Energy’s natural gas inventory at March 31, 2015

and December 31, 2014, respectively, with a carrying value of $8.7 million and $26.1 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, which expired on March 31, 2015, have been replaced with similar agreements that expire March 31, 2017.

Income Statement Presentation

The Company presents the revenues and expenses of its regulated businesses and its retail natural gas marketing businesses (including those activities of segments described in Note 10) within operating income, and it presents all other activities within other income (expense). Consistent with this presentation, the gain on the sale of CGT is reflected within operating income and the gain on the sale of SCI is reflected within other income (expense).

New Accounting Matters

In April 2014, the FASB issued new accounting guidance for reporting discontinued operations and disclosures of disposals of components of an entity. Under this new guidance, only those discontinued operations which represent a strategic shift that will have a major effect on an entity’s operations and financial results should be reported as discontinued operations in the financial statements. As permitted, the Company adopted this new guidance for the period ended December 31, 2014.

In May 2014, the FASB 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. Currently, the Company would be required to adopt the new guidance in the first quarter of 2017, and early adoption would not be permitted. However, the FASB may defer the adoption of this guidance for one year.  The Company has not determined the impact this guidance will have on its results of operations, cash flows or financial position.

In April 2015, the FASB issued new accounting guidance intended to simplify the presentation of debt issuance costs by requiring that such costs be deducted from the carrying amounts related to debt liabilities when presented in the balance sheet. As permitted, the Company expects to early adopt this new guidance in the fourth quarter of 2015.  The Company does not expect the adoption of this guidance to have a significant impact on its financial position.  The guidance will not affect the Company’s results of operations or cash flows.

In April 2015, the FASB issued new accounting guidance related to fees paid by a customer in a cloud computing arrangement.  Among other things, the new guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. The Company expects to adopt this new guidance in the first quarter of 2016. The Company is evaluating this guidance and has not determined what impact it will have on the Company’s 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 has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, the accompanying condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. Accordingly, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements.

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $498 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances. See also Note 4.

Plant to be Retired

SCE&G expects to retire three units that are or were coal-fired by 2020, subject to future developments in environmental regulations, among other matters. The net carrying value of these units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. The net carrying value of three previously retired units is recorded in regulatory assets within unrecovered plant (see Note 2).

New Accounting Matters

In May 2014, the FASB 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. Currently, Consolidated SCE&G would be required to adopt the new guidance in the first quarter of 2017, and early adoption would not be permitted. However, the FASB may defer the adoption of this guidance for one year.  Consolidated SCE&G has not determined the impact this guidance will have on its results of operations, cash flows or financial position.

In April 2015, the FASB issued new accounting guidance intended to simplify the presentation of debt issuance costs by requiring that such costs be deducted from the carrying amounts related to debt liabilities when presented in the balance sheet. As permitted, Consolidated SCE&G expects to early adopt this new guidance in the fourth quarter of 2015.  Consolidated SCE&G does not expect the adoption of this guidance to have a significant impact on its financial position.  The guidance will not affect Consolidated SCE&G’s results of operations or cash flows.

In April 2015, the FASB issued new accounting guidance related to fees paid by a customer in a cloud computing arrangement.  Among other things, the new guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. Consolidated SCE&G expects to adopt this new guidance in the first quarter of 2016. Consolidated SCE&G is evaluating this guidance and has not determined what impact it will have on its results of operations, cash flows or financial position.

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)

3 Months Ended

Mar. 31, 2015

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 March 31, 2015				As of December 31, 2014
Millions of dollars	Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	$	13	—		$	13	—
Commodity contracts	1		—		1		—
Energy management contracts	—		$	19	—		$	20
Liabilities:
Interest rate contracts	—		355		—		257
Commodity contracts	—		—		1		11
Energy management contracts	3		23		5		18

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

Financial instruments for which the carrying amount may not equal estimated fair value were as follows:

	March 31, 2015				December 31, 2014
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	5,541.6	$	6,501.6	$	5,697.2	$	6,592.1

SCEG

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

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

Financial instruments for which the carrying amount may not equal estimated fair value were as follows:

	March 31, 2015				December 31, 2014
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,303.3	$	5,119.2	$	4,308.6	$	5,070.9

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INCOME TAXES (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	$ 16
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	13
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound	2
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound	7
SCEG
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	16
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	13
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound	2
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound	$ 7

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AFFILIATED TRANSACTIONS - SCEG (SCEG)

3 Months Ended

Mar. 31, 2015

SCEG

Related Party Transactions Disclosure [Text Block]

AFFILIATED TRANSACTIONS

CGT transports natural gas to SCE&G to serve retail gas customers and certain electric generation requirements.  Prior to January 31, 2015, CGT was a wholly-owned subsidiary of SCANA, and SCE&G's transactions with CGT prior to January 31, 2015 were affiliated transactions. SCE&G's affiliated purchases from CGT totaled approximately $3.4 million and $5.5 million for the three months ended March 31, 2015 and 2014, respectively.  SCE&G's affiliated payables to CGT for transportation services were $3.3 million at December 31, 2014, and SCE&G's affiliated receivables from CGT related to such transportation services were $1.2 million at December 31, 2014.

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 $34.6 million and $53.4 million for the three months ended March 31, 2015 and 2014, respectively.  SCE&G’s payables to SEMI for such purposes were $10.6 million at March 31, 2015 and $12.6 million at December 31, 2014.

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 $70.1 million and $39.2 million for the three months ended March 31, 2015 and 2014, respectively.  SCE&G’s total sales to this affiliate were $69.7 million and $39.0 million for the three months ended March 31, 2015 and 2014, respectively. SCE&G’s receivable from this affiliate was $18.5 million at March 31, 2015 and $27.8 million at December 31, 2014.  SCE&G’s payable to this affiliate was $18.6 million at March 31, 2015 and $27.9 million at December 31, 2014.

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 $73.1 million and $76.2 million for the three months ended March 31, 2015 and 2014, respectively. Consolidated SCE&G's payables to SCANA Services for these services were $48.4 million at March 31, 2015 and $47.3 million at December 31, 2014.

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