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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

x

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

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2011

OR

o

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

For the Transition Period from                      to

2013

Commission
File Number

Registrant, State of Incorporation,
Address and Telephone Number

I.R.S. Employer
Identification No.

1-8809

1-3375

SCANA Corporation
(a South Carolina corporation)
South Carolina Electric & Gas Company (a South Carolina corporation)
100 SCANA Parkway, Cayce, South Carolina 29033
(803) 217-9000

57-0784499

1-3375

South Carolina Electric & Gas Company
(a South Carolina corporation)
100 SCANA Parkway, Cayce, South Carolina 29033
(803) 217-9000

57-0248695

Securities registered pursuant to Section 12(b) of the Act:

Each of the following classes or series of securities is

SCANA Corporation: Common stock, without par value, registered on The New York Stock Exchange.

Exchange

Title of each class

Registrant

Common Stock, without par value

SCANA Corporation

2009 Series A 7.70% Enhanced Junior Subordinated Notes

SCANA Corporation

2009 Series A 7.70% Enhanced Junior Subordinated Notes, registered on The New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

Title of each class

Registrant

South Carolina Electric & Gas Company: Series A Nonvoting Preferred Shares

South Carolina Electric & Gas Company

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
SCANA Corporation x         South Carolina Electric & Gas Company x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
SCANA Corporation o         South Carolina Electric & Gas Company o

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.             
SCANA Corporation Yes x No o     South Carolina Electric & Gas Company Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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 o     South Carolina Electric & Gas Company Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
         SCANA Corporation ox         South Carolina Electric & Gas Company x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Exchange Act Rule 12b-2).

SCANA Corporation

Large accelerated filer x

Accelerated filer 
o
Non-accelerated filer o
Smaller reporting company o

Accelerated filer o

Non-accelerated filer o
(Do not check if a smaller reporting company)

South Carolina Electric & Gas Company

Large accelerated filer o

Accelerated filer 
o
Non-accelerated filer x
Smaller reporting company o

Accelerated filer o

Non-accelerated filer x
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).
SCANA Corporation Yes o No x     South Carolina Electric & Gas Company Yes o No x

The aggregate market value of voting stock held by non-affiliates of SCANA Corporation was $5.0$6.85 billion at June 30, 201128, 2013, the last business day of the registrant's most recently completed second fiscal quarter, based on the closing price of $39.37$49.10 per share. South Carolina Electric & Gas Company is a wholly-ownedwholly‑owned subsidiary of SCANA Corporation and has no voting stock other than its common stock.stock, all of which is held beneficially and of record by SCANA Corporation. A description of registrants’ common stock follows:

Registrant

RegistrantDescription of
Common Stock

Shares Outstanding
at February 20, 2012

2014

SCANA Corporation

Without Par Value

130,295,890

141,144,841

South Carolina Electric & Gas Company

Without Par Value

40,296,147

(a)


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

Documents incorporated by reference: Specified sections of SCANA Corporation’s Proxy Statement, in connection with its 20122014 Annual Meeting of Shareholders, are incorporated by reference in Part III hereof.

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

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






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SCANA Corporation

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90

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Item 9B.

Other Information

143

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144

144

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145

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Statements included in this Annual Report on Form 10-K 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)

(1)

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

(2)

(2)

regulatory actions, particularly changes in rate regulation, regulations governing electric grid reliability and pipeline integrity, environmental regulations, and actions affecting the construction of new nuclear units;

(3)

(3)

current and future litigation;

(4)

(4)

changes in the economy, especially in areas served by subsidiaries of SCANA;

(5)

(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;

(6)

(7)

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

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

(9)

(7)

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

(10)

(8)

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

(9)

the effects of weather, including drought, especially in areas where the generation and transmission facilities of SCANA and its subsidiaries (the Company) are located and in areas served by SCANA’s subsidiaries;

(11)

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

(10)

(12)

payment and performance by counterparties and customers as contracted and when due;

(13)

(11)

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

(14)

(12)

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

(15)

(13)

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

(16)

(14)

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

(17)

(15)

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)

(16)

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

(19)

labor disputes;

(17)

(20)

labor disputes;

(18)

performance of SCANA’s pension plan assets;

(21)

(19)

changes in taxes;

(22)

(20)

inflation or deflation;

(23)

(21)

compliance with regulations;

(24)

(22)

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

(25)

(23)

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

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


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DEFINITIONS

Table of Contents

DEFINITIONS

Abbreviations used in this Form 10-K have the meanings set forth below unless the context requires otherwise:

TERM

MEANING

AER

Alternate Energy Resources, Inc.

AFC

TERM

MEANING

AFCAllowance for Funds Used During Construction

ANI

American Nuclear Insurers

ARO

AOCI

Accumulated Other Comprehensive Income

AROAsset Retirement Obligation

BACT

Best Available Control Technology

BLRA

Base Load Review Act

CAA

Clean Air Act, as amended

CAIR

Clean Air Interstate Rule

CAMR

CCR

Clean Air Mercury Rule

CCR

Coal Combustion Residuals

CEO

Chief Executive Officer

CFO

Chief Financial Officer

CERCLA

CFTC

Commodity Futures Trading Commission

CERCLAComprehensive 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 The Shaw Group, Inc.

Chicago Bridge & Iron Company N. V.

CSAPR

Cross-State Air Pollution Rule

CUT

Customer Usage Tracker

CWA

Clean Water Act

DHEC

South Carolina Department of Health and Environmental Control

Dodd-Frank

Dodd-Frank Wall Street Reform and Consumer Protection Act

DOE

United States Department of Energy

DOJ

United States Department of Justice

Dominion

DOT

Dominion Transmission, Inc.

DOT

United States Department of Transportation

DSM Programs

Demand Side Management Programs

DT

Dekatherm (one million BTUs)

Duke

Duke Energy Carolinas

EIZ Credits

South Carolina Capital Investment Tax Credits (formerly known as Economic Impact Zone Income Tax Credits)

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

eWNA

Pilot Electric WNA

FERC

United States Federal Energy Regulatory Commission

FEIS

Final Environmental Impact Statement

FSER

Final Safety Evaluation Report

Fuel Company

South Carolina Fuel Company, Inc.

GENCO

South Carolina Generating Company, Inc.

GHG

Greenhouse Gas

GPSC

Georgia Public Service Commission

GWh

Gigawatt hour

IRS

IRP

Integrated Resource Plan

IRSUnited States Internal Revenue Service

KVA

JEDA

Kilovolt ampere

South Carolina Jobs-Economic Development Authority

kW or kWh

KVA

Kilowatt or Kilowatt-hour

Kilovolt ampere

LLC

kWh

Limited Liability Company

Kilowatt-hour

LNG

TERMMEANING
Level 1A fair value measurement using unadjusted quoted prices in active markets for identical assets or liabilities
Level 2A 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 3A fair value measurement using unobservable inputs, including situations where there is little, if any, market activity for the asset or liability
LNGLiquefied Natural Gas

LOC

Lines of Credit

MACT

LTECP

Maximum Achievable Control Technology

SCANA Long-Term Equity Compensation Plan

MATS

Mercury and Air Toxics Standards

MCF or MMCF

Thousand Cubic Feet or Million Cubic Feet

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TERM

MEANING

MGP

Manufactured Gas Plant

MMBTU

Million British Thermal Units

MW or MWh

Megawatt or Megawatt-hour

NASDAQ

The NASDAQ Stock Market, Inc.

NEIL

NCUC

North Carolina Utilities Commission

NEILNuclear Electric Insurance Limited

NERC

North American Electric Reliability Corporation

New Units

Nuclear Units 2 and 3 to be constructedunder construction at Summer Station

NCUC

NPDES

North Carolina Utilities Commission

National Permit Discharge Elimination System

NMST

NRC

Negotiated Market Sales Tariff

NRC

United States Nuclear Regulatory Commission

NSR

NSPS

New Source Performance Standards

NSRNew Source Review

Nuclear Waste Act

Nuclear Waste Policy Act of 1982

NYMEX

New York Mercantile Exchange

NYSE

The New York Stock Exchange

OCI

Other Comprehensive Income

ORS

South Carolina Office of Regulatory Staff

PGA

Purchased Gas Adjustment

Pipeline Safety Act

PHMSA

The Pipeline Safety Improvement Act of 2002

PHMSA

United States Pipeline Hazardous Materials Safety Administration

Plan

Price-Anderson

SCANA Long-Term Equity Compensation Plan

Price-Anderson

Price-Anderson Indemnification Act

PRP

Potentially Responsible Party

PSNC Energy

Public Service Company of North Carolina, Incorporated

RCC

Replacement Capital Covenant

RCRA

RSA

Resource Conservation and Recovery Act

RES

Renewable Energy Standard

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

SCR

SEC

Selective Catalytic Reactor

SEC

United States Securities and Exchange Commission

SERC

SEMI

SERC Reliability Corporation

SEMI

SCANA Energy Marketing, Inc.

SERC

SERC Reliability Corporation
Southern Natural

Southern Natural Gas Company

Summer Station

V. C. Summer Nuclear Station

Transco

TERMMEANING
TranscoTranscontinental Gas Pipeline Corporation

TSR

Total Shareholder Return

USACE

VACAR

United States Army Corps of Engineers

VACAR

Virginia-Carolinas Reliability Group

VIE

Variable Interest Entity

Westinghouse

Westinghouse Electric Company LLC

Williams Station

A.M. Williams Generating Station, owned by GENCO

WNA

Weather Normalization Adjustment

5



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PART I

ITEM 1. BUSINESS

CORPORATE STRUCTURE

SCANA, a holding company, owns the following direct, wholly-owned subsidiaries:

SCE&G is engaged in the generation, transmission, distribution and sale of electricity to retail and wholesale customers and the purchase, sale and transportation of natural gas to retail customers.

GENCO owns Williams Station and sells electricity solely to SCE&G.

Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances.

PSNC Energy purchases, sells and transports natural gas to retail customers.

CGT transports natural gas in South Carolina and southeastern Georgia.

SCI provides fiber optic communications, ethernet services and data center facilities and builds, manages and leases communications towers in South Carolina, North Carolina and Georgia.

SEMI markets natural gas, primarily in the Southeast, and provides energy- related risk management services. SCANA Energy, a division of SEMI, markets natural gas in Georgia’s retail market.

ServiceCare, Inc. provides service contracts on home appliances and heating and air conditioning units.

SCANA Services, Inc. provides administrative, management and other services to SCANA’s subsidiaries and business units.

SCANA is incorporated in South Carolina, as is each of its direct, wholly- owned subsidiaries. In addition to the subsidiaries above, SCANA owns two other energy-related companies that are insignificant.

AND ORGANIZATION

SCANA is a South Carolina corporation created in 1984 as a holding company. SCANA holds directly or indirectly, all of the capital stock of the following subsidiaries, each of its subsidiaries. which is incorporated in South Carolina.

SCE&GEngaged in the generation, transmission, distribution and sale of electricity to retail and wholesale customers and the purchase, sale and transportation of natural gas to retail customers
GENCOOwns Williams Station and sells electricity solely to SCE&G
Fuel CompanyAcquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances
PSNC EnergyPurchases, sells and transports natural gas to retail customers
CGTTransports natural gas in South Carolina and southeastern Georgia
SCIProvides fiber optic communications, ethernet services and data center facilities and builds, manages and leases communications towers in South Carolina, North Carolina and Georgia
SEMIMarkets natural gas, primarily in the Southeast, and provides energy‑related risk management services. SCANA Energy, a division of SEMI, markets natural gas in Georgia’s retail market.
ServiceCare, Inc.Provides service contracts on home appliances and heating and air conditioning units
SCANA Services, Inc.Provides administrative, management and other services to SCANA’s subsidiaries and business units

SCANA owns one other energy‑related company that is insignificant and being liquidated.
SCANA and its subsidiaries had full-time, permanent employees as of February 20, 20122014 and 20112013 of 5,8895,989 and 5,877,5,842, respectively. SCE&G is an operating public utility incorporated in 1924 as a South Carolina corporation. SCE&G had full-time, permanent employees as of February 20, 2012 and 2011 of 3,202 and 3,173, respectively.

INVESTOR INFORMATION

SCANA’s and SCE&G’s annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed with or furnished to the SEC are available free of charge through SCANA’s internet website at www.scana.com (which is not intended as an active hyperlink) as soon as reasonably practicable after these reports are filed or furnished. Information on SCANA’s website is not part of this or any other report filed with or furnished to the SEC.


SCANA and SCE&G post information from time to time regarding developments relating to SCE&G’s new nuclear project on SCANA’s website at www.scana.com (which is not intended to be an active hyperlink; the information on SCANA’s website is not a part of this report or any other report or document that SCANA or SCE&G files with or furnishes to the SEC).  On SCANA’s homepage, there is a yellow box containing a link to the New Nuclear Development section of the website.  That section in turn contains a yellow box with a link to recent project news and updates.  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, and investors, media and others interested in SCE&G’s new nuclear project are encouraged to review this information.

SEGMENTS OF BUSINESS

For information with respect to major segments of business, see Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and the consolidated financial statements for SCANA and SCE&G (Note 12). All such information is incorporated herein by reference.

SCANA does not directly own or operate any significant physical properties. SCANA, through its subsidiaries, is engaged in the functionally distinct operations described below.

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Table of Contents

Regulated Utilities

SCE&G is engaged in the generation, transmission, distribution and sale of electricity to approximately 664,000678,000 customers and the purchase, sale and transportation of natural gas to approximately 317,000329,000 customers (each as of December 31, 2011)2013). SCE&G’s business experiences seasonal fluctuations, with generally higher sales of electricity during the summer and winter months because of air conditioning and heating requirements, and generally higher sales of natural gas during the winter months due to heating requirements. SCE&G’s electric service territory extends into 24 counties covering nearly 17,000 square miles in the central, southern and southwestern portions of South Carolina. The service area for natural gas encompasses all or part of 35 counties in South Carolina and covers approximately 22,600 square miles. More than 3.2 million persons live in the counties where SCE&G conducts its business. Resale customers include municipalities, electric cooperatives, other investor-owned utilities, registered marketers and federal and state electric agencies. Predominant industries served by SCE&G include chemicals, educational services, paper products, food products, lumber and wood products, health services, textile manufacturing, rubber and miscellaneous plastic products and fabricated metal products.

GENCO owns Williams Station and sells electricity solely to SCE&G.

Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances.

PSNC Energy purchases, sells and transports natural gas to approximately 487,000509,000 residential, commercial and industrial customers (as of December 31, 2011)2013). PSNC Energy serves 28 franchised counties covering 12,000 square miles in North Carolina. The predominant industries served by PSNC Energy include educational services, food products, health services, automotive, chemicals, non-woven textiles, electrical generation and construction-related materials.

construction.

CGT operates as an open access, transportation-only interstate pipeline company regulated by FERC. CGT operates in southeastern Georgia and in South Carolina and has interconnections with Southern Natural at Port Wentworth, Georgia and with Southern LNG, Inc. at Elba Island, near Savannah, Georgia. CGT also has interconnections with Southern Natural in Aiken County, South Carolina, and with Transco in Cherokee and Spartanburg counties, South Carolina. CGT’s customers include SCE&G (which uses natural gas for electricity generation and for gas distribution to retail customers), SEMI (which markets natural gas to industrial and sale for resale customers, primarily in the Southeast), municipalities, county gas authorities, federal and state agencies, marketers, power generators and industrial customers primarily engaged in the manufacturing or processing of ceramics, paper, metal, and textiles.

Nonregulated Businesses

SEMI markets natural gas primarily in the southeast and provides energy- relatedenergy-related risk management services. SCANA Energy, a division of SEMI, sells natural gas to approximately 455,000454,000 customers (as of December 31, 2011,2013, and includes approximately 80,00068,000 customers in its regulated division) in Georgia’s natural gas market. In third quarter 2013, SCANA Energy’s contract to serve as Georgia’s regulated provider of natural gas has beenwas renewed by the GPSC through August 31, 2014.2015.  SCANA Energy’s total customer base represents an approximately 30% share of the approximately 1.5 million customers in Georgia’s deregulated natural gas market. SCANA Energy remains the second largest natural gas marketer in Georgia.

SCI owns and operates a 500-mile1,125 mile fiber optic telecommunications network and ethernet network and data center facilities in South Carolina. Through a joint venture, SCI has an interest in an additional 2,280 miles of fiber in South Carolina, North Carolina and Georgia. SCI also provides tower site construction, management and rental services and sells towers in South Carolina and North Carolina.

SCI leases fiber optic capacity, data center space and tower space to certain affiliates at market rates.

The preceding Corporate Structure and Organization section describes other regulated and nonregulated businesses owned by SCANA.

COMPETITION

For a discussion of the impact of competition, see the Overview section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.

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CAPITAL REQUIREMENTS

SCANA’s regulated subsidiaries, including SCE&G, require cash to fund operations, construction programs and dividend payments to SCANA. SCANA’s nonregulated subsidiaries require cash to fund operations and dividend payments to SCANA. To replace existing plant investment and to expand to meet future demand for electricity and gas, SCANA’s regulated subsidiaries must attract the necessary financial capital on reasonable terms. Regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and these subsidiaries continue their construction programs, rate increases will be sought.

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The future financial position and results of operations of the regulated subsidiaries will be affected by their ability to obtain adequate and timely rate and other regulatory relief, when requested.

For a discussion of various rate matters and their impact on capital requirements, see the Regulatory Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and Note 2 to the consolidated financial statements for SCANA and SCE&G.

During the period 2012-2014,2014-2016, SCANA and SCE&G expect to meet capital requirements through internally generated funds, issuance of equity and short-term and long-term borrowings. SCANA and SCE&G expect that they have or can obtain adequate sources of financing to meet their projected cash requirements for the next 12 months and for the foreseeable future.

For a discussion of cash requirements for construction and nuclear fuel expenditures, contractual cash obligations, financing limits, financing transactions and other related information, see the Liquidity and Capital Resources section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.

SCANA’s ratios


Ratios of earnings to fixed charges were 2.87, 2.92, 2.84, 3.04 and 3.03 for each of the five years ended December 31, 2011, 2010, 2009, 2008 and 2007, respectively. SCE&G’s ratios of earnings to fixed charges2013, were 3.13, 3.18, 3.25, 3.51 and 3.40 for the same periods.

as follows:


December 31, 2013 2012 2011 2010 2009
SCANA 3.22 2.93 2.87 2.92 2.84
SCE&G 3.48 3.29 3.13 3.18 3.25
ELECTRIC OPERATIONS

Electric Sales

SCE&G’s sales of electricity and margins earned from the sale of electricity by customer classification as percentages of electric revenues for 20102012 and 20112013 were as follows:

 

 

Sales

 

Margins

 

Customer Classification

 

2010

 

2011

 

2010

 

2011

 

Residential

 

43

%

43

%

48

%

48

%

Commercial

 

32

%

32

%

33

%

33

%

Industrial

 

17

%

17

%

13

%

13

%

Sales for resale

 

6

%

6

%

4

%

4

%

Other

 

2

%

2

%

2

%

2

%

Total Territorial

 

100

%

100

%

100

%

100

%

NMST

 

%

%

%

%

Total

 

100

%

100

%

100

%

100

%

  Sales Margins
Customer Classification 2012 2013 2012 2013
Residential 43% 44% 50% 50%
Commercial 32% 33% 33% 33%
Industrial 17% 18% 13% 14%
Sales for resale 6% 2% 2% 1%
Other 2% 3% 2% 2%
Total 100% 100% 100% 100%
Sales for resale include sales to three municipalities and twoone electric cooperatives. Sales under NMST during 2011 includecooperative. Short-term system sales to seven investor-owned utilities or registered marketers and three federal/state electric agencies. were not significant for any period presented.
During 2010 sales under the NMST included sales to nine investor-owned utilities or registered marketers, two electric cooperatives and two federal/state electric agencies.

During 20112013 SCE&G recordedexperienced a net increase of approximately 3,6008,000 electric customers (growth rate of 0.5%1.2%), increasing its total electric customers to approximately 664,000678,000 at year end.

For the period 2012-2014,2014-2016, SCE&G projects total territorial KWhkWh sales of electricity to increase 0.7%0.6% annually (assuming normal weather), total retail sales growth of 0.6% annually (assuming normal weather), total electric customer base to increase 1.6%1.8% annually and territorial peak load (summer, in MW) to increase 1.0%1.9% annually. WhileSCE&G projects a retail kWh sales decrease of approximately 0.2% and customer growth of 1.1% from 2013 to 2014. SCE&G’s goal is to maintain a planning reserve margin of between 12%14% and 18%20%, however, weather and other factors affect territorial peak load and can cause actual generating capacity on any given day to fall below the reserve margin goal.

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Table of Contents

Electric Interconnections

SCE&G purchases all of the electric generation of GENCO’s Williams Station under a Unit Power Sales Agreement which has been approved by FERC. Williams Station has a net generating capacity (summer rating) of 605 MW.


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SCE&G’s transmission system, which extends over a large part of the central, southern and southwestern portions of South Carolina, interconnects with Duke Energy Carolinas, LLC, Duke Energy Progress, Energy Carolinas,Inc., Santee Cooper, Georgia Power Company Oglethorpe Power Corporation and the Southeastern Power Administration’s Clarks Hill (Thurmond) Project. SCE&G Duke Energy Carolinas, Progress Energy Carolinas, Santee Cooper, Dominion Virginia Power and ALCOA Power Generating, Inc. (Yadkin Division), are membersis a member of VACAR, one of several geographic divisions within the SERC. SERC is one of eight regional entities with delegated authority from NERC for the purpose of proposing and enforcing reliability standards approved by FERC.  SERC is divided geographically into five diverse sub-regions that are identified as Central, Delta, Gateway, Southeastern and VACAR. The regional entities and all members of NERC work to safeguard the reliability of the bulk power systems throughout North America. For a discussion of the impact certain legislative and regulatory initiatives may have on SCE&G’s transmission system, see Electric Operations within the Overview section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.

Fuel Costs and Fuel Supply

The average cost of various fuels and the weighted average cost of all fuels (including oil) for the years 2009-20112011-2013 follow:

 

 

Cost of Fuel Used

 

 

 

2009

 

2010

 

2011

 

Per MMBTU:

 

 

 

 

 

 

 

Nuclear

 

$

.48

 

$

.72

 

$

.88

 

Coal

 

4.36

 

4.49

 

4.47

 

Natural Gas

 

4.61

 

5.48

 

4.86

 

All Fuels (weighted average)

 

3.61

 

3.80

 

3.80

 

Per Ton: Coal

 

108.39

 

110.63

 

109.91

 

Per thousand cubic feet (MCF): Gas

 

4.81

 

5.64

 

5.01

 

 Cost of Fuel Used
 2011 2012 2013
Per MMBTU: 
  
  
Nuclear$0.88
 $0.94
 $1.11
Coal4.47
 4.49
 4.28
Natural Gas4.86
 3.71
 4.63
All Fuels (weighted average)3.80
 3.56
 3.53
Per Ton: Coal109.91
 111.72
 104.63
Per MCF: Gas5.01
 3.80
 4.69
The sources and percentages of total MWh generation by each category of fuel for the years 2009-20112011-2013 and the estimates for the years 2012-20142014-2016 follow:

 

 

% of Total MWh Generated

 

 

 

Actual

 

Estimated

 

 

 

2009

 

2010

 

2011

 

2012

 

2013

 

2014

 

Coal

 

51

%

52

%

50

%

46

%

44

%

46

%

Nuclear

 

18

%

21

%

19

%

20

%

22

%

20

%

Hydro

 

4

%

4

%

3

%

4

%

4

%

4

%

Natural Gas & Oil

 

27

%

23

%

28

%

29

%

29

%

29

%

Biomass

 

 

 

 

1

%

1

%

1

%

Total

 

100

%

100

%

100

%

100

%

100

%

100

%

Six of

 % of Total MWh Generated
 Actual Estimated
 2011 2012 2013 2014 2015 2016
Coal50% 50% 45% 50% 49% 45%
Nuclear19% 19% 24% 21% 21% 24%
Hydro3% 3% 4% 4% 4% 4%
Natural Gas & Oil28% 28% 26% 24% 25% 26%
Biomass
 
 1% 1% 1% 1%
Total100% 100% 100% 100% 100% 100%
In 2013, the sevenCompany used coal to generate electricity at six fossil fuel-fired plants, use coal.including its cogeneration facility located in Charleston, South Carolina. Unit trains and, in some cases, trucks and barges deliverdelivered coal to these plants.

SCE&G completed the retirement of one of these plants (comprised of three units) in 2012 and 2013 and intends to retire certain other coal-fired generating units by 2018, subject to future developments in environmental regulations, among other matters. One of the units to be retired by 2018 was fueled with coal prior to 2013, but is expected to be fueled exclusively with natural gas until its retirement.

Coal is primarily obtained through long-term supply contracts and spot market purchases.contracts. Long-term contracts exist with suppliers located in eastern Kentucky, Tennessee and West Virginia. These contracts provide for approximately 3.52.8 million tons annually, which is substantially all expected coal purchases for 2012.annually. Sulfur restrictions on the contract coal range from 1%1.0% to 2%1.6%. These contracts expire at various times through 2014.2016. Spot market purchases are expected to continuemay occur when needed or when prices are believed to be favorable.

SCANA and SCE&G believe that SCE&G’s operations comply with all applicable regulations relating to the discharge of sulfur dioxide and nitrogen oxide. See additional discussion at Environmental Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.

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On January 27, 2011, SCE&G, for itself and as agent for Santee Cooper, and Westinghouse entered intoare parties to a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, SCE&G has to supply enriched product to Westinghouse and Westinghouse will supply enriched nuclear fuel assemblies for Summer Station Unit 1 and the New Units. Westinghouse will be SCE&G’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements of Summer Station Unit 1 and the New Units through 2033. SCE&G is dependent upon Westinghouse for providing fuel assemblies for the new AP1000 passive reactors in the New Units in the current and anticipated future absence of other commercially viable sources. Westinghouse


The Consortium currently provides maintenance and engineering support to Summer Station Unit 1 under a services alliance arrangement, andagreement.  Although SCE&G has also contracted for Westinghouseprovided the Consortium with notice of its election to terminate the existing agreement, it is anticipated that SCE&G will enter into new agreements to provide similar support services to Summer Station Unit 1 and to the New Units upon their completion and commencement of commercial operation.

  Those new agreements may, but will not necessarily, be between SCE&G and the Consortium.

In addition, to the above-described contracts for fuel fabrication and related services, SCE&G has contracts covering its nuclear fuel needs for uranium, conversion services and enrichment services. These contracts have varying expiration dates in the next 11 years.through 2024. SCE&G believes that it will be able to renew contracts as they expire or enter into similar contractual arrangements with other suppliers of nuclear fuel materials and services and that sufficient capacity for nuclear fuel supplies and processing exists to preclude the impairment of normal operations of its nuclear generating units.

SCE&G can store spent nuclear fuel on-site until at least 2017 and expects to expand itshas commenced construction of a dry cask storage capacityfacility to accommodate the spent fuel output for the life of Summer Station Unit 1 through dry cask storage or1. SCE&G may evaluate other technology as it becomes available. In addition, Summer Station Unit 1 has sufficient on-site storage capacity to permit storage of the entire reactor core in the event that complete unloading should become desirable or necessary. For information about the contract with the DOE regarding disposal of spent fuel, see Hazardous and Solid Wastes within the Environmental Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.

GAS OPERATIONS

Gas Sales-Regulated

Regulated sales of natural gas by customer classification as a percent of total regulated gas revenues sold or transported for 20102012 and 20112013 were as follows:

 

 

SCANA

 

SCE&G

 

Customer Classification

 

2010

 

2011

 

2010

 

2011

 

Residential

 

56.1

%

54.5

%

45.7

%

43.4

%

Commercial

 

27.2

%

27.2

%

28.8

%

28.6

%

Industrial

 

11.6

%

12.5

%

22.0

%

23.9

%

Transportation Gas

 

5.1

%

5.8

%

3.5

%

4.1

%

Total

 

100.0

%

100.0

%

100.0

%

100.0

%

  SCANA SCE&G
Customer Classification 2012 2013 2012 2013
Residential 54.7% 55.6% 44.3% 43.5%
Commercial 26.1% 26.0% 27.5% 27.4%
Industrial 11.8% 12.5% 22.3% 25.6%
Transportation Gas 7.4% 5.9% 5.9% 3.5%
Total 100.0% 100.0% 100.0% 100.0%
For the three-year period 2012-2014,2014-2016, SCANA projects total consolidated sales of regulated natural gas in DTsMMBTUs to increase 0.9%1.4% annually (assuming(excluding transportation and assuming normal weather). Annual projected increases over such period in DTMMBTU sales include residential of 1.2%2.1%, commercial of 0.9%0.8% and industrial of 0.8%.

For the three-year period 2012-2014,2014-2016, SCE&G projects total consolidated sales of regulated natural gas in DTsMMBTUs to increase 0.4%0.8% annually (assuming(excluding transportation and assuming normal weather). Annual projected increases over such period in DTMMBTU sales include residential of 0.4%1.0%, commercial of 0.3%0.6% and industrial of 1.1%1.0%.

For the three-year period 2012-2014,2014-2016, SCANA’s and SCE&G’s total consolidated regulated natural gas customer base is projected to increase annually 1.5%2.3% and 1.2%1.9%, respectively.  During 20112013 SCANA recorded a net increase of approximately 8,80018,000 regulated gas customers (growth rate of 1.1%2.2%), increasing its regulated gas customers to approximately 804,000.837,000.  Of this increase, SCE&G recorded a net increase of approximately 3,3007,000 gas customers (growth rate of 1.1%2.1%), increasing its total gas customers to approximately 317,000329,000 (as of December 31, 2011)2013).

Demand for gas changes primarily due to the effect of weather and the price relationship between gas and alternate fuels.

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Gas Cost, Supply and Curtailment Plans

South Carolina

SCE&G purchases natural gas under contracts with producers and marketers in both the spot and long-term markets. The gas is delivered to South Carolina through firm transportation agreements with Southern Natural (expiring in 2013)2014 and 2018), Transco (expiring in 2013 and 2017) and CGT (expiring in 2012,2014, 2018, 2023 and 2026). The maximum daily volume of gas that SCE&G is entitled to transport under these contracts is 161,144 DT222,404 MMBTU from Southern Natural, 64,652 DTMMBTU from Transco and 424,429 DT425,929 MMBTU from CGT. Additional natural gas volumes may be delivered to SCE&G’s system as capacity is available through interruptible transportation.

The daily volume of gas that SEMI is entitled to transport under its service agreementagreements with CGT (expiring in 2016, 2017 and 2023) on a firm basis is 78,083 DT.

82,615 MMBTU.

SCE&G purchased natural gas, including fixed transportation, at an average cost of $5.88$5.35 per MCF during 20112013 and $6.38$4.73 per MCF during 2010.

2012.

SCE&G was allocated 5,4375,382 MMCF of natural gas storage capacity on the systems of Southern Natural and Transco. Approximately 4,2134,039 MMCF of gas were in storage on December 31, 2011.2013. To meet the requirements of its high priority natural gas customers during periods of maximum demand, SCE&G supplements its supplies of natural gas with two LNG liquefaction and storage facilities. The LNG plants are capable of storing the liquefied equivalent of 1,880 MMCF of natural gas. Approximately 1,7591,635 MMCF (liquefied equivalent) of gas were in storage on December 31, 2011.

North Carolina

2013.

PSNC Energy purchases natural gas under contracts with producers and marketers on a short-term basis at currentmarket based prices and on a long-term basis for reliability assurance at first of the month index prices plus a reservation charge.charge in certain cases. Transco and Dominion deliver thetransports natural gas to North Carolina through transportation agreements with varying expiration dates ranging through 2016.2032. On a peak day, PSNC Energy may transportis capable of receiving daily transportation volumes of natural gas under these contracts, on autilizing firm basiscontracts of 281,110 DT610,062 MMBTU from Transco and 7,331 DT from Dominion.

Transco.

PSNC Energy purchased natural gas, including fixed transportation, at an average cost of $5.54$5.13 per DTMMBTU during 20112013 compared to $5.95$4.65 per DTMMBTU during 2010.

2012.

To meet the requirements of its high priority natural gas customers during periods of maximum demand, PSNC Energy supplements its supplies of natural gas with underground natural gas storage services and LNG peaking services. Underground natural gas storage service agreements with Dominion Transmission, Inc., Columbia Gas Transmission, Transco and Spectra Energy provide for storage capacity of approximately 13,000 MMCF. Approximately 12,00010,000 MMCF of gas were in storage under these agreements at December 31, 2011.2013.  In addition, PSNC Energy’s LNG facility can store the liquefied equivalent of 1,000 MMCF of natural gas with regasification capability of approximately 100 MMCF per day.  Approximately 800900 MMCF (liquefied equivalent) of gas were in storage at December 31, 2011.2013.  LNG storage service agreements with Transco, Cove Point LNG and Pine Needle LNG provide for 1,300 MMCF (liquefied equivalent) of storage space. Approximately 1,2001,100 MMCF (liquefied equivalent) were in storage under these agreements at December 31, 2011.

2013.

SCANA and SCE&G believe that supplies under long-term contracts and supplies available for spot market purchase are adequate to meet existing customer demands and to accommodate growth.

Gas Marketing-Nonregulated

SEMI markets natural gas and provides energy-related risk management services primarily in the Southeast. In addition, SCANA Energy, a division of SEMI, markets natural gas to approximately 455,000454,000 customers (as of December 31, 2011)2013) in Georgia’s natural gas market. SCANA Energy’s total customer base represents an approximate 30% share of the approximately 1.5 million customers in Georgia’s deregulated natural gas market. SCANA Energy remains the second largest natural gas marketer in the state.

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Risk Management

Table

For a discussion of Contents

Risk Management

SCANA and SCE&G have establishedrisk management policies and procedures, and risk limitssee Note 6 to control the level of market, credit, liquidity and operational and administrative risks assumed by them. 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 to oversee and review the risk management process and infrastructureconsolidated financial statements for SCANA and eachSCE&G.


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REGULATION
For a discussion of its subsidiaries. The Risk Management Committee, which is comprised of certain officers, including a Risk Management Officerlegislative and several senior officers, apprisesregulatory initiatives being implemented that will affect SCE&G’s transmission system, see Electric Operations within the Board of Directors with regard to the management of risk and brings to the Board’s attention any areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

REGULATION

SCANA is subject to the jurisdiction of the SEC as to the issuance of certain securities and other matters and is subject to the jurisdiction of the FERC as to certain acquisitions and other matters.

SCE&G is subject to the jurisdiction of the SEC as to the issuance of certain securities and other matters; the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters; and FERC as to issuance of short-term borrowings, certain acquisitions and other matters.

GENCO is subject to the jurisdiction of the SCPSC as to issuance of securities (other than short-term borrowings) and is subject to the jurisdiction of FERC as to issuance of short-term borrowings, accounting, certain acquisitions and other matters.

PSNC Energy is subject to the jurisdiction of the NCUC as to gas rates, service, issuance of securities (other than notes with a maturity of two years or less or renewals of notes with a maturity of six years or less), accounting and other matters.

CGT is subject to the jurisdiction of FERC as to transportation rates, service, accounting and other matters.

SCANA Energy is regulated by the GPSC through its certification as a natural gas marketer in Georgia and specifically is subject to the jurisdiction of the GPSC as to retail prices for customers served under the regulated provider contract.

SCE&G and GENCO are subject to regulation under the Federal Power Act, administered by FERC and DOE, in the transmission of electric energy in interstate commerce and in the sale of electric energy at wholesale for resale, as well as with respect to licensed hydroelectric projects and certain other matters, including accounting. See the Regulatory MattersOverview section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.


For a discussion of the regulatory jurisdictions to which SCANA and its subsidiaries are subject, see the Regulatory Matters section of Management's Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.
SCE&G and GENCO havehas obtained FERC authority to issue short-term indebtedness (pursuantand to assume liabilities as a guarantor(pursuant to Section 204 of the Federal Power Act). SCE&G may issue up to $1.2 billion of unsecured promissory notes, or commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, bankers, and dealers in commercial paper in amounts not to exceed $600 million. GENCO mayhas obtained FERC authority to issue upshort-term indebtedness not to exceed $150 million outstanding with maturity dates of such short-term indebtedness.one year or less. The authority to make such issuancesdescribed herein will expire in October 2012.

2014.

SCE&G holds licenses under the Federal Power Act for each of its hydroelectric projects. The RSA allows natural gas distribution companies to request annual adjustments to rates to reflect changes in revenues and expenses and changes in investment. Such annual adjustments are subject to certain qualifying criteria and review by the SCPSC.SCElicenses expire as follows:
Project
License
Expiration
Saluda (Lake Murray)2014
Fairfield Pumped Storage/Parr Shoals2020
Stevens Creek2025
Neal Shoals2036
SCE&G is presently operating the Saluda hydroelectric project under an annual license (scheduled to expire in August) while its long-term re-licensing application is being reviewed by FERC.

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SCE&G holds licenses under the Federal Power Act for each of its hydroelectric projects. The licenses expire as follows:

Project

License
Expiration

Saluda (Lake Murray)

2012

Fairfield Pumped Storage/Parr Shoals

2020

Stevens Creek

2025

Neal Shoals

2036

At the termination of a license under the Federal Power Act, FERC may extend or issue a new license to the previous licensee, or may issue a license to another applicant, or the federal government may take over the related project. If the federal government takes over a project or if FERC issues a license to another applicant, the federal government or the new licensee, as the case may be, must pay the previous licensee an amount equal to its net investment in the project, not to exceed fair value, plus severance damages.

For a discussion of legislative and regulatory initiatives being implemented that will affect SCE&G’s transmission system, see Electric Operations within the Overview section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G.

SCE&G is subject to regulation by the NRC with respect to the ownership, construction, operation and decommissioning of its currently operating and planned nuclear generating facilities. The NRC’s jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety, antitrust considerations and environmental impact. In addition, the Federal Emergency Management Agency reviews, in conjunction with the NRC, certain aspects of emergency planning relating to the operation of nuclear plants.

RATE MATTERS

For a discussion of the impact of various rate matters, see the Regulatory Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G, and Note 2 to the consolidated financial statements for SCANA and SCE&G.


Prior to the first billing cycle of January 2014, SCE&G's retail electric rates for its residential and certain small commercial customers included an eWNA approved by the SCPSC, which largely mitigated the impact of weather on electric margins. In connection with a December 2013 SCPSC order, SCE&G discontinued the eWNA.
SCE&G’s retail electric rates include certain costs associated with its DSM Programs as authorized by the SCPSC. More specifically, these rates include the costs and lost net margin revenue associated with DSM Programs, along with an incentive for investing in such programs.

Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%.

In May 2011 and in November 2012, the SCPSC approved updated capital cost schedules sought by SCE&G that, among other matters, incorporated then-identifiable additional capital costs and revised substantial completion dates for the New Units, and included amounts to resolve certain claims. Details of these SCPSC approvals are further described in Notes 2 and 10 to the consolidated financial statements for SCANA and SCE&G.


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In December 2012, the SCPSC approved a 4.23% overall increase in SCE&G's retail electric base rates and authorized SCE&G an allowed return on common equity of 10.25% (related to non-BLRA expenditures). The SCPSC also approved a mid-period reduction to the cost of fuel component in rates, as well as a reduction in the DSM Programs component rider to retail rates, among other things. See Note 2 to the consolidated financial statements for SCANA and SCE&G for additional details.

SCE&G’s gas rate schedules for its residential, small commercial and small industrial customers include a WNA approved by the SCPSC, which is in effect for bills rendered for billing cycles in November through April. The WNA increases tariff rates if weather is warmer than normal and decreases rates if weather is colder than normal. The WNA does not change the seasonality of gas revenues, but reduces fluctuations in revenues and earnings caused by abnormal weather.

SCE&G’s retail electric rates include certain costs associated with the Company’s DSM Programs as authorized by the SCPSC. More specifically, these costs include the costs and lost net margin revenue associated with DSM Programs, along with an incentive for investing in such programs. In August 2010, SCE&G implemented an eWNA on a one-year pilot basis for its electric customers and it will continue on a pilot basis unless modified or terminated by the SCPSC.

PSNC Energy is authorized by the NCUC to utilize a CUT which allows PSNC Energy to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption, whether impacted by weather or other factors.

Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. In September 2011, the SCPSC approved an increase of $52.8 million or 2.4% under the BLRA for the annual revised rates adjustment filing. The new retail electric rates were effective for bills rendered on and after October 30, 2011.

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

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In May 2009, two intervenors filed separate appeals of the SCPSC order with the South Carolina Supreme Court. With regard to the first appeal, which challenged the SCPSC’s prudency finding, the South Carolina Supreme Court issued an opinion on April 26, 2010, affirming the decision of the SCPSC. As for the second appeal, the South Carolina Supreme Court reversed the SCPSC’s decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G’s share of the project, as originally approved by the SCPSC, was $4.5 billion in 2007 dollars. Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court’s ruling, however, did not affect the project schedule or disturb the SCPSC’s issuance of a certificate of environmental compatibility and public convenience and necessity, which is required to construct the New Units. On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule that reflected the removal of the contingency reserve and incorporated then identifiable capital costs of $173.9 million (in 2007 dollars), and by order dated May 16, 2011, the SCPSC approved the updated capital costs schedule as outlined in the petition.

On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving a further updated capital cost and construction schedule that incorporates additional identifiable capital costs of approximately $6 million (SCE&G’s portion in 2007 dollars) related to new federal healthcare laws, information security measures and certain minor design modifications. That petition also includes increased capital costs of approximately $12 million (SCE&G’s portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 million (SCE&G’s portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, facilities and information technology systems required to support the New Units and their personnel. Future petitions would be filed for any costs arising from the resolution of the commercial claims discussed in the OTHER MATTERS — Nuclear Generation section of Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 1 of the consolidated financial statements (e.g., those related to COL delays, design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock conditions at the site).

Fuel Cost Recovery Procedures

The SCPSC’s fuel cost recovery procedure determines the fuel component in SCE&G’s retail electric base rates annually based on projected fuel costs for the ensuing 12-month period, adjusted for any over-collection or under-collection from the preceding 12-month period. The statutory definition of fuel costs includes certain variable environmental costs, such as ammonia, lime, limestone and catalysts consumed in reducing or treating emissions. The definition also includes the cost of emission allowances used for sulfur dioxide, nitrogen oxide, mercury and particulates. SCE&G may request a formal proceeding concerning its fuel costs at any time should circumstances dictate such a review.

time. SCPSC proceedings related to SCE&G’s retail electric rates are established in part using a&G's cost of fuel component approved byare described in Note 2 to the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased byconsolidated financial statements for SCANA and SCE&G. In February 2011, SCE&G requested authorization to increase the cost of fuel component of its retail electric rates to be effective with the first billing cycle of May 2011. On March 17, 2011, SCE&G, ORS and SCEUC entered into a settlement agreement in which SCE&G agreed to recover its actual base fuel under-collected balance as of April 30, 2011 over a two-year period commencing with the first billing cycle of May 2011. The settlement agreement also provided that SCE&G would be allowed to charge and accrue carrying costs monthly on the deferred balance. By order dated April 26, 2011, the SCPSC approved the settlement agreement. The next annual hearing to review base rates for fuel costs is scheduled for March 22, 2012.

SCE&G’s natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred, including costs related to hedging natural gas purchasing activities.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. The annual PGA hearingSCPSC proceedings related to review SCE&G’s gas purchasing policies and procedures was conducted in November 2011 before the SCPSC. The SCPSC issued an order in January 2012 finding that SCE&G’s gas purchasing policies and practices during the review period of August 1, 2010 through July 31, 2011, were reasonable and prudent and authorized the suspension of SCE&G’s&G's natural gas hedging program.

tariffs are described in Note 2 to the consolidated financial statements for SCANA and SCE&G.


PSNC Energy is subject to a Rider D rate mechanism which allows it to recover from customers all prudently incurred gas costs, andincluding gas costs that were uncollectible from certain uncollectible expenses related to gas cost.customers. The Rider D rate mechanism also allows it 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 adjusted periodically to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collections 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 January 2012, NCUC proceedings related to PSNC Energy's rates are described in Note 2 to the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in February 2012.

In December 2011, in connection with PSNC Energy’s 2011 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, 2011. On February 2, 2012, the Public Staff of the NCUC filed a motion requesting that the NCUC reconsider and modify its order by reassigning certain charges (totaling approximately $0.4 million) from the cost of gas. PSNC Energy cannot predict the outcome of this matter, but the Company does not believe it will have a material effect on the Company’s results of operations, cash flows, orconsolidated financial condition.

In October 2011, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in November 2011.

In October 2010, the NCUC approved a 12.5 cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in November 2010. In February 2010, the NCUC approved a ten cent per therm increase in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in March 2010.

statements for SCANA.

ENVIRONMENTAL MATTERS

Federal and state authorities have imposed environmental regulations and standards relating primarily to air emissions, wastewater discharges and solid, toxic and hazardous waste management. Developments in these areas may require that equipment and facilities be modified, supplemented or replaced. The ultimate effect of these regulations and standards upon existing and proposed operations cannot be predicted. For a more complete discussion of how these regulations and standards impact SCANA and SCE&G, see the Environmental Matters section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for SCANA and SCE&G and Note 10 to the consolidated financial statements for SCANA and SCE&G.

OTHER MATTERS

For a discussion of SCE&G’s insurance coverage for Summer Station Unit 1and1 and the New Units, see Note 10 to the consolidated financial statements for SCANA and SCE&G.



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ITEM 1A. RISK FACTORS

The risk factors that follow relate in each case to SCANA and its subsidiaries, and where indicated the risk factors also relate to SCE&G and its consolidated affiliates.

Commodity price changes, delays and other factors may affect the operating cost, capital expenditures and competitive positions of the Company’s and Consolidated SCE&G’s energy businesses, thereby adversely impacting results of operations, cash flows and financial condition.

Our energy businesses are sensitive to changes in coal, natural gas, oiluranium and other commodity prices (as well as their transportation costs) and availability. Any such changes could affect the prices these businesses charge, their operating costs and the competitive position of their products and services. Consolidated SCE&G is permitted to recover the prudently incurred cost of purchased power and fuel (including transportation) used in electric generation through retail customers’ bills, but purchased power and fuel cost increases affect electric prices and therefore the competitive position of electricity against other energy sources. In addition, when natural gas prices are low enough relative to coal to require the dispatch of gas-fired electric generation ahead of coal-fired electric generation, higher inventories of coal, with related increased carrying costs, may result. This may adversely affect our results of operations, cash flows and financial position.

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In the case of regulated natural gas operations, costs prudently incurred for purchased gas and pipeline capacity may be recovered through retail customers’ bills. However, in both our regulated and deregulated natural gas markets, increases in gas costs affect total retail prices and therefore the competitive position of gas relative to electricity and other forms of energy. Gas cost increases alsoAccordingly, customers able to do so may result in lowerswitch to alternative forms of energy and reduce their usage by customersof gas from the Company and Consolidated SCE&G. Customers unable to switch to alternate fuels. Increases in fuel costsalternative fuels or suppliers may also result in higher prices for and thus lowerreduce their usage of electricity by customers.

gas from the Company and Consolidated SCE&G.

Certain construction-related commodities, such as copper and aluminum used in our transmission and distribution lines and in our electrical equipment, and steel, concrete and rare earth elements, have experienced significant price fluctuations due to changes in worldwide demand. To operate our air emissions control equipment, we use significant quantities of ammonia, limestone and lime. With EPA-mandated industry-wide compliance requirements for air emissions controls, increased demand for these reagents, combined with the increased demand for low sulfur coal, may result in higher costs for coal and reagents used for compliance purposes.

The costs of large capital projects, such as the Company’s and Consolidated SCE&G’s construction for environmental compliance and its construction of the New Units and associated transmission, are significant and are subject to a number of risks and uncertainties that may adversely affect the cost, timing and completion of the projects.

The Company’s and Consolidated SCE&G’s businesses are capital intensive and require significant investments in energy generation and in other internal infrastructure projects, including projects for environmental compliance. For example, SCE&G and Santee Cooper have agreed to jointly own, contract the design constructand construction of, and operate the New Units, which will be two 1,117-megawatt1,250 MW (1,117 MW, net) nuclear units at SCE&G’s Summer Station, in pursuit of which they have committed and are continuing to commit significant resources towards project development, permitting, site preparation and long lead-time procurement. Substantial additional resources will be required for the construction and operation of the New Units upon receipt of requisite approvals.resources. In addition, planning and construction of significant new transmission resources areinfrastructure is necessary to support the New Units and areis under way as an integral part of the project. Achieving the intended benefits of any large construction project is subject to many uncertainties. For instance, the ability to stay withinadhere to established budgets and timeframes may be affected by many variables, such as the regulatory and legal processes associated with securing permits and licenses and necessary amendments to them within projected timeframes, the availability of labor and materials at estimated costs, the availability and cost of financing, and weather. There also may be contractor or supplier performance issues or adverse changes in their creditworthiness, and unforeseen difficulties meeting critical regulatory requirements. There may be unforeseen engineering problems or unanticipated changes in project design or scope. Our ability to complete construction projects (including new baseload generation) as well as our ability to maintain current operations at reasonable cost could be affected by the availability of key components or commodities, increases in the price of or the unavailability of labor, commodities or other materials, increases in lead times for components, new or enhanced environmental requirements, supply chain failures (whether resulting from the foregoing or other factors), and disruptions in the transportation of components, commodities and fuels. Some of the foregoing issues have been experienced in the construction of the New Units. A discussion of certain of those matters can be found under New Nuclear Construction Matters in Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for SCANA and SCE&G.

Should the construction of the New Units materially and adversely deviate from the schedules, estimates, and projections submitted to and approved by the SCPSC pursuant to the BLRA, the SCPSC could disallow the additional capital

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costs that result from the deviations to the extent that it is deemed that the Company's failure to anticipate or avoid the deviation, or to minimize the resulting expenses, was imprudent, considering the information available at the time. Depending upon the magnitude of any such disallowed capital costs, the Company could be moved to evaluate the prudency of continuation, adjustment to, or termination of the New Units project.

Furthermore, joint venturejointly owned projects, such as the current construction of the New Units, are subject to the risk that one or more of the joint venture partnersowners becomes either unable or unwilling to continue to fund project financial commitments, new partnersjoint owners cannot be secured at equivalent financial terms, or changes in the joint ventureownership make-up will increase project costs and/or delay the completion.

To the extent that delays occur, costs become unrecoverable, or we otherwise become unable to effectively to manage and complete our capital projects, our results of operations, cash flows and financial condition may be adversely affected.

The use of derivative instruments could result in financial losses and liquidity constraints. The Company and Consolidated SCE&G do not fully hedge against financial market risks or price changes in commodities. This could result in increased costs, thereby resulting in lower margins and adversely affecting results of operations, cash flows and financial condition.

The Company and Consolidated SCE&G use derivative instruments, including futures, forwards, options and swaps, to manage our commodity and financial market risks. The Company also uses such derivative instruments to manage certain commodity (i.e. natural gas) market risk. We could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities and interest ratefinancial contracts or if a counterparty fails to perform under a contract.

The Company strives to manage commodity price exposure by establishing risk limits and entering into contracts to offset some of our positions (i.e., to hedge our exposure to demand, market effects of weather and other changes in commodity prices). We do not hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility or our hedges are not effective, results of operations, cash flows and financial condition may be diminished.

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Furthermore, recent federal legislation (Dodd-Frank)Dodd-Frank affects the use and reporting of derivative instruments. The regulations under this new legislation are still being finalizedprovide for substantial additional regulation of over-the-counter and their impact on the use ofsecurity-based derivative instruments, among other things, and require numerous rule-makings by the CFTC and the SEC to implement. The Company and Consolidated SCE&G have determined that they meet the end-user exception to mandatory clearing of swaps under Dodd-Frank. In addition, the Company and Consolidated SCE&G have taken steps to ensure that they are not the party required to report these transactions in real-time (the "reporting party") by transacting solely with swap dealers, major swap participants and financial institutions, when possible, as well as entering into reporting party agreements with counterparties who also are not swap dealers, major swap participants or financial institutions, which establishes that those counterparties are obligated to report the transactions in accordance with applicable Dodd-Frank regulations. While these actions minimize the reporting obligations of the Company, they do not eliminate required recordkeeping for any Dodd-Frank regulated transactions. Moreover, the Company retains reporting responsibility for certain types of swaps, such as the annual reporting of trade options. Despite qualifying for the end-user exception to mandatory clearing and ensuring that neither the Company nor Consolidated SCE&G is the reporting party to a transaction required to be reported in real-time, we cannot predict when the final regulations will be determined at this time.

issued or what requirements they will impose.

Changing and complex laws and regulations to which the Company and Consolidated SCE&G are subject could adversely affect revenues, increase costs, or curtail activities, thereby adversely impacting results of operations, cash flows and financial condition.

The Company and Consolidated SCE&G operate under the regulatory authority of the United States government and its various regulatory agencies, including the FERC, NRC, SEC, IRS, EPA, CFTC and PHMSA. In addition, the Company and Consolidated SCE&G are subject to regulation by agencies of the state governments of South Carolina, North Carolina and Georgia includingvia regulatory agencies, state environmental commissions, and state employment commissions. Accordingly, the Company and Consolidated SCE&G must comply with extensive federal, state and local laws and regulations. Such governmental oversight and regulation broadly and materially affect the operation of our business. In addition to many other aspects of our business, these requirements impact the licensing, siting, construction and operation of facilities. They affect our management of safety, the reliability of our electric and natural gas transmission system,systems, the physical and cyber security of key assets, customer conservation through demand-side management programs,DSM Programs, information security, the issuance of securities and borrowing of money, financial reporting, interactioninteractions among affiliates, the payment of dividends and employment programs and practices. Changes to governmental regulations are continual and wepotentially costly to effect compliance. We cannot predict the future course of

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changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on the Company’s or Consolidated SCE&G’s businesses.


Furthermore, changes in or uncertainty in monetary, fiscal, or regulatory policies of the Federal government may adversely affect the debt and equity markets and the economic climate for the nation, region or particular industries, such as ours or those of our customers. The Company and Consolidated SCE&G could be adversely impacted by changes in tax policy, such as the loss of Production Tax Credits related to the construction of the New Units.
The Company and Consolidated SCE&G are subject to extensive rate regulation which could adversely affect operations. In particular, Large capital projects, DSM Programs results and/or increases in operating costs may lead to requests for regulatory relief, such as rate increases, which may be denied, in whole or part, by rate regulators. Rate increases may also result in reductions in customer usage of electricity or gas, legislative action and lawsuits.

SCE&G’s electric operations in South Carolina and the Company’s gas distribution operations in South Carolina and North Carolina are regulated by state utilities commissions. In addition, the construction of the New Units by SCE&G is subject to rate regulation by the SCPSC via the BLRA. The Company’s interstate gas pipeline, SCE&G’s electric transmission system and Consolidated SCE&G’s generating facilities are subject to extensive regulation and oversight from the FERC, NRC and SCPSC. Our gas marketing operations in Georgia are subject to state regulatory oversight and, for a portion of its operations, to rate regulation. There can be no assurance that Georgia’s gas delivery regulatory framework will remain unchanged as market conditions evolve. Although we believe that we have constructive relationships with the regulators, our ability to obtain rate treatment that will allow us to maintain reasonable rates of return is dependent upon regulatory determinations, and there can be no assurance that we will be able to implement rate adjustments when sought.

The Company and Consolidated SCE&G are subject to numerous environmental laws and regulations that require significant capital expenditures, can increase our costs of operations and which may impact our business plans or expose us to environmental liabilities.

The Company and Consolidated SCE&G are subject to extensive federal, state and local environmental laws and regulations, including those relating to water quality and air emissions (such as reducing nitrogen oxide, sulfur dioxide, mercury and particulate matter). Some form of regulation may be forthcomingis expected at the federal and possibly state levels to impose regulatory requirements specifically directed at reducing GHG emissions from fossil fuel-fired electric generating units. On September 20, 2013, the EPA re-proposed NSPS for emissions of carbon dioxide from newly constructed fossil fuel-fired electric generating units. Standards, regulations, or guidelines are also expected for existing units by June 1, 2014, to be made final no later than June 1, 2015. A number of bills have been introduced in Congress that seek to require GHG emissions reductions from fossil fuel-fired electric generation facilities, natural gas facilities and other sectors of the economy, although none have yet been enacted. On February 16, 2012, the EPA issued the finalized MATS for power plants that requires reduced emissions from new and existing coal and oil-fired electric utility steam generating facilities. The EPA has proposed requirements for cooling water intake structures to meet BACT, andthethe best technology available, and the EPA presently is drafting a final rule regarding the handling of coal ash and other combustion by-products produced by power plant operations. Furthermore, the EPA has announced that it expects to overhaulproposed new standards under the Clean Water Act rulesCWA governing effluent limitation standardsguidelines for coal-fired power plants.

electric generating units.

Compliance with these environmental laws and regulations requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emissions fees and permitting at our facilities. These expenditures have been significant in the past and are expected to continue or even increase in the future. Changes in compliance requirements or more restrictive interpretations by governmental authorities of existing requirements may impose additional costs on us (such as the clean-up of MGP sites or additional emission allowances) or require us to incur additional capital expenditures or curtail some of our cost savings activities (such as the recycling of fly ash and other coal combustion products for beneficial use). Compliance with any GHG emission reduction requirements, including any mandated renewable portfolio standards, also may impose significant costs on us, and the resulting price increases to our customers may lower customer consumption. Such costs of compliance with environmental regulations could negatively impact our industry, our business and our results of operations and financial position, especially if emissions or discharge limits are reduced or more onerous permitting requirements or additional regulatory requirements are imposed.

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Renewable and/or alternative electric generation portfolio standards may be enacted at the federal or state level. Some states already have them, though currently South Carolina does not. Such standards could direct us to build or otherwise acquire generating capacity derived from renewable/alternative energy sources (generally, renewable energy such as biomass, solar, wind and tidal, and excluding fossil fuels, nuclear or hydro facilities). Such renewable/alternative energy may not be readily available in our service territories, if at all, and could be extremely costly to build, acquire, and operate. Resulting increases in the price of electricity to recover the cost of these types of generation, if approved by regulatory commissions,


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could result in lower usage of electricity by our customers. Although we cannot predict whether such standards will be adopted at the federal level or in South Carolina or their specifics if adopted, compliance with such potential portfolio standards could significantly impact our industry, our capital expenditures, and our results of operations and financial position.


The compliance costs of these environmental laws and regulations are important considerations in the Company's and Consolidated SCE&G's strategic planning and, as a result, significantly affect the decisions to construct, operate, and retire facilities, including generating facilities. In effecting compliance with MATS, SCE&G announced in 2012 that six of its oldest and smallest coal-fired units would be taken off-line or temporarily switched from coal to natural gas prior to closure in 2018. One of these units was retired in late 2012. Two other of these units were retired in late 2013.
The Company and Consolidated SCE&G are vulnerable to interest rate increases, which would increase our borrowing costs, and may not have access to capital at favorable rates, if at all. Additionally, potential disruptions in the capital and credit markets may further adversely affect the availability and cost of short-term funds for liquidity requirements and our ability to meet long-term commitments; each could in turn adversely affect our results of operations, cash flows and financial condition.

The Company and Consolidated SCE&G rely on the capital markets, particularly for publicly offered debt and equity, as well as the banking and commercial paper markets, to meet our financial commitments and short-term liquidity needs if internal funds are not available from operations. Changes in interest rates affect the cost of borrowing. The Company’s and Consolidated SCE&G’s business plans, which include significant investments in energy generation and other internal infrastructure projects, reflect the expectation that we will have access to the capital markets on satisfactory terms to fund commitments. Moreover, the ability to maintain short-term liquidity by utilizing commercial paper programs is dependent upon maintaining satisfactory short-term debt ratings and the existence of a market for our commercial paper generally.

The Company’s and Consolidated SCE&G’s ability to draw on our respective bank revolving credit facilities is dependent on the ability of the banks that are parties to the facilities to meet their funding commitments and on our ability to timely renew such facilities. Those banks may not be able to meet their funding commitments to the Company or Consolidated SCE&G if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from us and other borrowers within a short period of time. Longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to liquidity needed for our business. Any disruption could require the Company and Consolidated SCE&G to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures or other discretionary uses of cash. Disruptions in capital and credit markets also could result in higher interest rates on debt securities, limited or no access to the commercial paper market, increased costs associated with commercial paper borrowing or limitations on the maturities of commercial paper that can be sold (if at all), increased costs under bank credit facilities and reduced availability thereof, and increased costs for certain variable interest rate debt securities of the Company and Consolidated SCE&G.

Disruptions in the capital markets and its actual or perceived effects on particular businesses and the greater economy also adversely affect the value of the investments held within SCANA’s pension trust. A significant long-term decline in the value of these investments may require us to make or increase contributions to the trust to meet future funding requirements. In addition, a significant decline in the market value of the investments may adversely impact the Company’s and Consolidated SCE&G’s results of operations, cash flows and financial position, including its shareholders’ equity.

A downgrade in the credit rating of SCANA or any of SCANA’s subsidiaries, including SCE&G, could negatively affect our ability to access capital and to operate our businesses, thereby adversely affecting results of operations, cash flows and financial condition.

Various rating agencies rate SCANA’s long-term senior unsecured debt, SCE&G’s long-term senior secured debt, and the long-term senior unsecured debt of PSNC Energy as investment grade. In addition, ratings agencies maintain ratings on the short-term debt of SCANA, SCE&G, Fuel Company (which ratings are based upon the guarantee of SCE&G) and PSNC Energy. If these rating agencies were to lower the outlook or downgrade any of these ratings, particularly to below investment grade, borrowing cost on new issuances would increase, which would diminish financial results, and the potential pool of investors and funding sources could decrease.

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OneIn 2011, one rating agency by action taken in 2011, downgraded both the short-term and senior unsecured long-term debt of SCANA. In 2013, another rating agency revised the outlook for SCANA and its subsidiaries to negative from stable. These downgrades and lowered outlook have increased SCANA’sthe short-term borrowing rate and decreased the average maturityrates of its short-term debt,SCANA and may have the effect of increasing SCANA’sthe long-term


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borrowing rate.rates of SCANA and SCE&G. Although access to the short-term market has not been adversely impacted, this could change under different market conditions.

SCANA’s leverage ratio of long- and short-term debt to capital was approximately 58%56% at December 31, 2011.2013. SCANA has publicly announced its desire to maintain its leverage ratio at levels between 54% and 57%, but SCANA’s ability to achieve and maintain those levelsdo so depends on a number of factors. In the future, if SCANA is not able to achieve and maintain its leverage ratio within the desired range, the Company’s debt ratings may be affected, it may be required to pay higher interest rates on its long- and short-term indebtedness, and its ability to access to the capital markets may be limited.

impaired.

Operating results may be adversely affected by natural disasters, man-made mishaps and abnormal weather.

The Company has delivered less gas and received lower prices for natural gas in deregulated markets and consequently earned less income when weather conditions have been milder than normal.normal, and as a consequence earned less income from those operations. During 2010, the SCPSC approved SCE&G’s implementation of an eWNA on a pilot basis.basis; it was discontinued at the end of 2013. Mild weather in the future could diminish the revenues and results of operations and harm the financial condition of the Company and Consolidated SCE&G if the eWNA is not extended on&G. Hot or cold weather could result in higher bills for customers and result in higher write-offs of receivables and in a permanent basis.greater number of disconnections for non-payment. In addition, for the Company and Consolidated SCE&G, severe weather can be destructive, causing outages and property damage, adversely affecting operating expenses and revenues.

Natural disasters (such as electromagnetic events and the 2011 earthquake and tsunami in Japan) or man-made mishaps (such as the San Bruno, California natural gas transmission pipeline failure, or the Kingston, Tennessee coal ash pond failure)failure, and cyber-security failures experienced by many businesses) could have direct significant impacts on the Company and Consolidated SCE&G and on our key contractors and suppliers or could indirectly impact us through changes to federal, state or local policies, laws and regulations, and have a significant impact on our financial position, operating expenses, and cash flows.

Potential competitive changes may adversely affect our gas and electricity businesses due to the loss of customers, reductions in revenues, or write-down of stranded assets.

The utility industry has been undergoing structural change for a number of years, resulting in increasing competitive pressures on electric and natural gas utility companies. Competition in wholesale power sales has been introducedvia a RTO/ISO (Regional Transmission Organization/Independent System Operator) is in effect across much of the country, but the Southeastern utilities have retained the traditional bundled, vertically integrated structure. Should a RTO/ISO-market be implemented in the Southeast, potential risks emerge from reliance on a national level. volatile wholesale market prices as well as increased costs associated with new delivery transmission and distribution infrastructure.

Some states have also mandated or encouraged competition at theunbundled retail level. Increasedcompetition. Should this occur in South Carolina, increased competition may create greater risks to the stability of utility earnings generally and may in the future reduce earnings from retail electric and natural gas sales. In a deregulated environment, formerly regulated utility companies that are not responsive to a competitive energy marketplace may suffer erosion in market share, revenues and profits as competitors gain access to their customers. In addition, the Company’s and Consolidated SCE&G’s generation assets would be exposed to considerable financial risk in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, a write-down in the value of the related assets would be required.

The Company and Consolidated SCE&G are subject to the risk of loss of sales due to the growth of distributed generation especially in the form of renewable power such as solar photovoltaic systems. As a result of federal and state subsidies and potential regulations allowing third-party retail sales, the growth of such distributed generation could be significant in the future. Such growth will lessen Company and Consolidated SCE&G sales and slow growth, potentially causing higher rates to customers.

The Company and SCE&G are subject to risks associated with changes in business and economic climate which could adversely affect revenues, results of operations, cash flows and financial condition and could limit access to capital.

Sales, sales growth and customer usage patterns are dependent upon the economic climate in the service territories of the Company and SCE&G, which may be affected by regional, national or even international economic factors. Some economic sectors important to our customer base may be particularly affected. Adverse events, economic or otherwise, may also affect the operations of suppliers and key customers. Such events may result in the loss of suppliers or customers, in costs

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charged by suppliers, in changes into customer usage patterns and in the failure of customers to make timely payments to us. With respect to the Company, such events also could adversely impact the results of operations through the recording of a goodwill or other asset impairment. The success of local and state governments in attracting new industry to our service territories is important to our sales and growth in sales, as are stable levels of taxation (including property, income or other taxes) which may be affected by local, state, or federal budget deficits, adverse economic climates generally or legislative or regulatory actions. Budget cutbacks also adversely affect funding levels of federal and state support agencies and non-profit organizations that assist low income customers with bill payments.

In addition, conservation and demand side management efforts and/or technological advances may cause or enable customers to significantly reduce their usage of the Company’s and SCE&G’s products and adversely affect sales, sales growth, and customer usage patterns.

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Factors that generally could affect our ability to access capital include economic conditions and our capital structure. Much of our business is capital intensive, and achievement of our capital plan and long-term growth targets is dependent, at least in part, upon our ability to access capital at rates and on terms we determine to be attractive. If our ability to access capital becomes significantly constrained, our interest costs will likely increase and our financial condition and future results of operations could be significantly harmed.

Problems with operations could cause us to curtail or limit our ability to serve customers or cause us to incur substantial costs, thereby adversely impacting revenues, results of operations, cash flows and financial condition.

Critical processes or systems in the Company’s or Consolidated SCE&G’s operations could become impaired or fail from a variety of causes, such as equipment breakdown, transmission line failure, information systems failure or security breach, the effects of drought (including reduced water levels) on the operation of emission control or other generation equipment, and the effects of a pandemic or terrorist attack on our workforce or facilities or on the ability of vendors and suppliers to maintain services key to our operations.

In particular, as the operator of power generation facilities, many of which entered service prior to 1985 and may be difficult to maintain, Consolidated SCE&G could incur problems, such as the breakdown or failure of power generation or emission control equipment, transmission lines,equipment, or other equipment or processes which would result in performance below assumed levels of output or efficiency. The operation of the New Units may entail additional cycling of our coal-fired generation facilities and may thereby increase the number of unplanned outages at those facilities. In addition, any such breakdown or failure may result in Consolidated SCE&G purchasing emission allowances or replacement power at market rates, if such allowances and replacement power are available at all. These purchases are subject to state regulatory prudency reviews for recovery through rates. If replacement power is not available, such problems could result in interruptions of service (blackout or brownout conditions) in all or part of SCE&G’s territory or elsewhere in the region. These purchases are subject to state regulatory prudency reviews for recovery through rates. Similarly, a gas transmission or distribution line failure of the Company or Consolidated SCE&G could affect the safety of the public, destroy property, and interrupt our ability to serve customers.

Events such as these could entail substantial repair costs, litigation, fines and penalties, and damage to reputation, each of which could have an adverse effect on the Company’s revenues, results of operations, and financial condition.

Insurance may not be available or adequate to respond to these events.

A failure of the Company to maintain the physical and cyber security of its operations may result in the failure of operations, damage to equipment, or loss of information, and could result in a significant adverse impact to the Company's financial position, results of operations and cash flows.
The Company depends on maintaining the physical and cyber security of its operations and assets.  As much of our business is part of the nation's critical infrastructure, the loss or impairment of the assets associated with that portion of our business could have serious adverse impacts on the customers and communities that we serve.  Virtually all of the Company's operations are dependent in some manner upon our cyber systems, which encompass electric and gas transmission and distribution operations, nuclear and fossil fuel generating plants, human resource and customer systems and databases, information system networks, and systems containing confidential corporate information.  Cyber systems, such as those of the Company, are often targets of malicious cyber attacks.  A successful physical or cyber attack could lead to outages, failure of operations of all or portions of our businesses, damage to key components and equipment, and exposure of confidential customer, employee, or corporate information.  The Company may not be readily able to recover from such events.  In addition, the failure to secure our operations from such physical and cyber events may cause us reputational damage.  Litigation, penalties and claims from a number of parties, including customers, regulators and shareholders, may ensue.  Insurance may

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not be adequate to respond to these events.  As a result, the Company's financial position, results of operations, and cash flows may be adversely affected.

SCANA’s ability to pay dividends and to make payments on SCANA’s debt securities may be limited by covenants in certain financial instruments and by the financial results and condition of its subsidiaries, thereby adversely impacting the valuation of our common stock and our access to capital .

We are a holding company that conducts substantially all of our operations through our subsidiaries. Our assets consist primarily of investments in subsidiaries. Therefore, our ability to meet our obligations for payment of interest and principal on outstanding debt and to pay dividends to shareholders and corporate expenses depends on the earnings, cash flows, financial condition and capital requirements of our subsidiaries, and the ability of our subsidiaries, principally Consolidated SCE&G, PSNC Energy and SEMI, to pay dividends or to advance or repay funds to us. Our ability to pay dividends on our common stock may also be limited by existing or future covenants limiting the right of our subsidiaries to pay dividends on their common stock. Any significant reduction in our payment of dividends in the future may result in a decline in the value of our common stock. Such a decline in value could limit our ability to raise debt and equity capital.

A significant portion of Consolidated SCE&G’s generating capacity is derived from nuclear power, the use of which exposes us to regulatory, environmental and business risks. These risks could increase our costs or otherwise constrain our business, thereby adversely impacting our results of operations, cash flows and financial condition. These risks will increase as the New Units are developed.

In 2011,2013, Summer Station Unit 1, operated by SCE&G, provided approximately 55.6 million MWh, or 19%24% of our generation capacity. Ifgeneration. When the New Units are completed, our generating capacity and the percentage of total generating capacity represented by nuclear sources isare expected to increase. Hence, SCE&G is subject to various risks of nuclear generation, which include the following:

·

The potential harmful effects on the environment and human health resulting from a release of radioactive materials in connection with the operation of nuclear facilities and the storage, handling and disposal of radioactive materials;

·

Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States;

·

The possibility that new laws and regulations could be enacted that could adversely affect the liability structure that currently exists in the United States;
Uncertainties with respect to procurement of nuclear fuel and the storage of spent nuclear fuel;

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·Uncertainties with respect to contingencies if insurance coverage is inadequate; and

·

Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their operating lives.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate capital expenditures at nuclear plants such as ours. In addition, although we have no reason to anticipate a serious nuclear incident, if a major incident should occur at a domestic nuclear facility, it could harm our results of operations, cash flows and financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. Finally, in today’s environment, there is a heightened risk of terrorist attack on the nation’s nuclear facilities, which has resulted in increased security costs at our nuclear plant.

Failure to retain and attract key personnel could adversely affect the Company’s and Consolidated SCE&G’s operations and financial performance.

Implementation

As with many other utilities, a significant portion of our strategic plan and growth strategy requires that weworkforce will be eligible for retirement during the next few years. We must attract, retain and develop executive officers and other professional, technical and craft employees with the skills and experience necessary to successfully manage, operate and grow our business. Competition for these employees is

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high, and in some cases we must compete for these employees on a regional or national basis. We may be unable to attract and retain these personnel. Further, the Company’s or Consolidated SCE&G’s ability to construct or maintain generation or other assets requires the availability of suitable skilled contractor personnel. We may be unable to obtain appropriate contractor personnel at the times and places needed. Labor disputes with employees or contractors covered by collective bargaining agreements also could adversely affect implementation of our strategic plan and our operational and financial performance.

The Company and Consolidated SCE&G are subject to the risk that strategic decisions made by us either do not result in a return of or on invested capital or might negatively impact our competitive position, which can adversely impact our results of operations, cash flows, financial position, and access to capital.

From time to time, the Company and Consolidated SCE&G make strategic decisions that may impact our direction with regard to business opportunities, the services and technologies offered to customers or that are used to serve customers, and the generating plantplants and other infrastructure that form the basis of much of our business. These strategic decisions may not result in a return of or on our invested capital, and the effects of these strategic decisions may have long-term implications that are not likely to be known to us in the short-term. Changing political climates and public attitudes may adversely affect the ongoing acceptability of strategic decisions that have been made (and, in some cases, previously approved by regulators), to the detriment of the Company or Consolidated SCE&G. Over time, these strategic decisions or changing attitudes toward such decisions, which could be adverse to the Company’s or Consolidated SCE&G’s interests, may have a negative effect on our results of operations, cash flows and financial position, as well as limit our ability to access capital.

The Company and Consolidated SCE&G are subject to the reputational risks that may result from a failure to adhere to high standards of compliance with laws and regulations, ethical conduct, operational effectiveness, and safety of employees, customers and the public. These risks could adversely affect the valuation of our common stock and the Company’s and Consolidated SCE&G’s access to capital.

The Company and Consolidated SCE&G are committed to comply with all laws and regulations, to focus on the safety of employees, customers and the public, to maintain the privacy of information related to our customers and employees and to maintain effective communications with the public and key stakeholder groups, particularly during emergencies and times of crisis. The Company and Consolidated SCE&G also are committed to operational excellence and, through our Code of Conduct and Ethics, to maintain high standards of ethical conduct in our business operations. A failure to meet these commitments may subject the Company and Consolidated SCE&G not only to fraud, litigation and financial loss, but also to reputational risk that could adversely affect the valuation of SCANA’s stock, adversely affect the Company’s and Consolidated SCE&G’s access to capital, and result in further regulatory oversight.

Insurance may not be available or adequate to respond to these events.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not Applicable

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Table of Contents

ITEM 2. PROPERTIES

SCANA owns no significant property other than the capital stock of each of its subsidiaries. It holds, directly or indirectly, all of the capital stock of each of its subsidiaries.

SCE&G’s&G's bond indenture, securing the First Mortgage Bonds issued thereunder, constitutes a direct mortgage lien on substantially all of its electric utility property. GENCO’sGENCO's Williams Station is also subject to a first mortgage lien which secures certain outstanding debt of GENCO.

For a brief description of the properties of SCANA’s other subsidiaries, which are not significant as defined in Rule 1-02 of Regulation S-X, see Item 1. BUSINESS—SEGMENTS OF BUSINESS—Nonregulated Businesses.

ELECTRIC PROPERTIES

The following map indicates significant electric generation properties, which are further described below. Natural gas transmission and distribution properties, though not depicted on the map, are also described below.

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Table of Contents

ELECTRIC PROPERTIES

SCE&G owns each oftable shows the electric generating facilities listed below unless otherwise noted.

Facility

 

Present
Fuel Capability

 

Location

 

Year
In-Service

 

Net Generating
Capacity
(Summer Rating) (MW)

Steam Turbines:

 

 

 

 

 

 

 

 

Summer(1)

 

Nuclear

 

Jenkinsville, SC

 

1984

 

644

McMeekin

 

Coal/Gas

 

Irmo, SC

 

1958

 

250

Canadys

 

Coal/Gas

 

Canadys, SC

 

1962

 

385

Wateree

 

Coal

 

Eastover, SC

 

1970

 

684

Williams(2)

 

Coal

 

Goose Creek, SC

 

1973

 

605

Cope

 

Coal

 

Cope, SC

 

1996

 

415

Kapstone(3)

 

Biomass/Coal

 

Charleston, SC

 

1999

 

85

Combined Cycle:

 

 

 

 

 

 

 

 

Urquhart(4)

 

Coal/Gas/Oil

 

Beech Island, SC

 

1953/2002

 

553

Jasper

 

Gas/Oil

 

Hardeeville, SC

 

2004

 

869

Hydro(5):

 

 

 

 

 

 

 

 

Saluda

 

 

 

Irmo, SC

 

1930

 

200

Fairfield Pumped Storage

 

 

 

Jenkinsville, SC

 

1978

 

576

and their net generating capacity as of December 31, 2013.


(1)Represents SCE&G’s two-thirds portion of Summer Station Unit 1 (one-third owned by Santee Cooper).

(2)The coal-fired steam unit at Williams Station is owned by GENCO.

(3)

  Net Generating Capacity 
 In-ServiceSummer 
 Date(MW) 
Coal-Fired Steam:   
  McMeekin - Near Irmo, SC1958250
*
  Wateree - Eastover, SC1970684
 
  Williams - Goose Creek, SC1973605
 
  Cope - Cope, SC1996415
 
  Kapstone - Charleston, SC199985
 
    
Gas-Fired Steam - Urquhart Unit 3 - Beech Island, SC195395
*
    
Nuclear - V. C. Summer - Parr, SC (reflects SCE&G's 66.7% ownership share)1984647
 
    
Internal Combustion Turbines:   
  Peaking units - various locations in SC1968-1999352
 
  Urquhart Combined Cycle - Beech Island, SC2002458
 
  Jasper Combined Cycle - Jasper, SC2004852
 
    
Hydro:   
  Saluda - Irmo, SC1930200
 
  Other hydro units - various locations in or bordering SC1905-191418
 
  Fairfield Pumped Storage - Parr, SC1978576
 

* As described in Note 2 to the consolidated financial statements for SCANA and SCE&G, receives shaft horsepower from Kapstone Charleston Kraft, LLC, a biomass/coal cogeneration facility,under plans announced in 2012, SCE&G has retired or intends to operate SCE&G’s generator.

(4)Two combined-cycle turbines burn natural gas or fuel oil to produce 330 MW of electric generation and use exhaust heat to power two 64 MW turbines at the Urquhart Generating Station. Unit 3 is a 95 MWretire six coal-fired steam unit.

(5)SCE&G also owns three other hydro units in South Carolina that were placed in service in 1905 and 1914 and havewith an aggregate net generating capacity (summer rating) of 21 MW.

SCE&G owns 16 combustion turbine peaking730 MW by 2018, subject to future developments in environmental regulations, among other matters. As of December 31, 2013, three of these units fueled by gas and/or oil located at various sites in SCE&G’s service territory. These turbines were placed in service at various times from 1961 to 2010 and havehad been retired (with an aggregate net generating capacity, summer rating, of 355 MW.

385 MW) and are not included in the table above. Another unit, Urquhart Unit 3, was fueled with coal prior to 2013, and is expected to be fueled with natural gas until its retirement in 2018.


SCE&G owns 441436 substations having an aggregate transformer capacity of 30 million KVA. The transmission system consists of 18,2953,307 miles of lines, and the distribution system consists of 6,76318,397 pole miles of overhead lines and 7,004 trench miles of underground lines.

NATURAL GAS DISTRIBUTION AND TRANSMISSION PROPERTIES

SCE&G’s&G's natural gas system includes 448 miles of transmission pipeline of up to 20 inches in diameter that connect its distribution system with Southern Natural, Transco and CGT. SCE&G’s distribution system consists of 16,54916,450 miles of distribution mains and related service facilities. SCE&G also owns two LNG plants, one located near Charleston, South Carolina, and the other in Salley, South Carolina. The Charleston facility can liquefy up to 6 MMCF per day and store the liquefied equivalent of 980 MMCF of natural gas. The Salley facility can store the liquefied equivalent of 900 MMCF of natural gas and has no liquefying capabilities. The LNG facilities have the capacity to regasify approximately 60 MMCF per day at Charleston and 90 MMCF per day at Salley.

CGT’s natural gas system consists of 1,469 miles of transmission pipeline of up to 24 inches in diameter. CGT’s system transports gas to its customers from the transmission systems of Southern Natural at Port Wentworth, Georgia and Aiken County, South Carolina, Southern LNG, Inc. at Elba Island, near Savannah, Georgia and Transco in Cherokee and from Port Wentworth and Elba Island, Georgia.

Spartanburg counties in South Carolina.

PSNC Energy’s natural gas system consists of 606594 miles of transmission pipeline of up to 24 inches in diameter that connect its distribution systems with Transco. PSNC Energy’s distribution system consists of 10,20120,411 miles of distribution mains and related service facilities. PSNC Energy owns one LNG plant with storage capacity of 1,000 MMCF, the capacity to liquefy up to 4 MMCF per day and the capacity to regasify approximately 100 MMCF per day. PSNC Energy also owns, through a wholly-owned subsidiary, 33.21% of Cardinal Pipeline Company, LLC, which owns a 105-mile transmission pipeline in North Carolina. In addition,

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Table of Contents

PSNC Energy owns, through a wholly-owned subsidiary, 17% of Pine Needle LNG Company, LLC. Pine Needle owns and operates a liquefaction, storage and regasification facility in North Carolina.


ITEM 3.  LEGAL PROCEEDINGS

Certain material legal proceedings and environmental and regulatory matters and uncertainties, some of which remain outstanding at December 31, 2011, are described below. These issues affect the Company and, to the extent indicated, also affect Consolidated SCE&G.

In December 2009, the EPA issued a final finding that atmospheric concentrations of GHG endanger public health and welfare within the meaning of Section 202(a) of the CAA. The rule, which became effective in January 2010, enables the EPA to regulate GHG emissions under the CAA. The EPA has committed to issue new rules regulating such emissions in 2012. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

In 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels.  CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide.  SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements.  On July 6, 2011 the EPA issued the CSAPR.  This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. Air quality control installations that SCE&G and GENCO have already completed should assist the Company in complying with the CSAPR and the reinstated CAIR.  The Company will continue to pursue strategies to comply with all applicable environmental regulations.  Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

In June 2010, the EPA issued a final rule for a one-hour ambient air quality standard for sulfur dioxide. This new standard may require some of SCE&G’s smaller coal-fired units to reduce their sulfur dioxide emissions to a level to be determined by EPA and/or DHEC. The costs incurred to comply with this new standard are expected to be recovered through rates.

In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units. In March 2011, the EPA proposed new standards for mercury and other specified air pollutants.  The rule, which becomes effective on April 16, 2012, provides up to four years for facilities to meet the standards.  The rule is currently being evaluated by the Company. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

SCE&G has been named, along with 53 others, by the EPA as a PRP at the AER Superfund site located in Augusta, Georgia. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that was completed in 2010. A clean-up cost has been estimated and the PRPs have agreed to an allocation of those costs based primarily on volume and type of material each PRP sent to the site. SCE&G’s allocation did not have a material impact on its results of operations, cash flows or financial condition.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC. SCE&G anticipates that major remediation activities at these sites will continue until 2014 and will cost an additional $8.3 million.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.

PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy’s actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. PSNC Energy has recorded a liability and associated regulatory asset of approximately $3.1 million, the estimated remaining liability at December 31, 2011. PSNC Energy expects to recover through rates any cost, net of insurance recovery, allocable to PSNC Energy arising from the remediation of these sites.

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Table of Contents

Litigation

In May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette and Mark Rudd, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Communications, Inc. was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiffs alleged that SCE&G made improper use of certain electric transmission easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications and asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment.  While SCE&G and SCI believe their actions were consistent with governing law and the applicable documents granting easements and rights-of-way, this case, with Circuit Court approval in August 2010, has been settled as to all easements and rights of ways currently containing fiber optic communications lines in South Carolina.  This settlement did not have a material impact on the Company’s results of operations, cash flows or financial condition.

SCANA and SCE&G are also engaged in various other claims and litigation incidental to their business operations which management anticipates will be resolved without a material impact on their respective results of operations, cash flows or financial condition.

In addition, certain material regulatory and environmental matters and uncertainties, some of which remain outstanding at December 31, 2013, are described in the Rate Matters section of Note 2 and in the Environmental section of Note 10 to the consolidated financial statements of SCANA and SCE&G.


ITEM 4.  MINE SAFETY DISCLOSURES

Not Applicable

25


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Table of Contents

EXECUTIVE OFFICERS OF SCANA CORPORATION

The executive officers are elected at the annual meeting of the Board of Directors, held immediately after the annual meeting of shareholders, and hold office until the next such annual meeting, unless (1) a resignation is submitted, (2) the Board of Directors shall otherwise determine or (3) as provided in the By-laws of SCANA. Positions held are for SCANA and all subsidiaries unless otherwise indicated.


Name

Age

Name 

Age

Positions Held During Past Five Years

Dates

Kevin B. Marsh

58

56

Chairman of the Board and Chief Executive Officer and Director

President and Chief Operating Officer -SCANA

Officer-SCANA

President and Chief Operating Officer-SCE&G

2011-present

2011-present

*-2011

Jimmy E. Addison

53

51

Executive Vice President

Chief Financial Officer

Senior Vice President

2012-present

*-present

*-2012

Jeffrey B. Archie

56

54

Senior Vice President

Senior Vice President and Chief Nuclear Officer-SCE&G

Senior Vice President-SCANA
Vice President of Nuclear Plant Operations-SCE&G

2009-present
2010-present

2009-present

*-2009

George J. Bullwinkel

65

63

President and Chief Operating Officer-SEMI, SCI and ServiceCare

Senior Vice President-SCANA

*-present

*-present

Sarena D. Burch

56

54

Senior Vice President-Fuel Procurement and Asset Management- SCEManagement-SCE&G
and PSNC Energy

Senior Vice President-SCANA

*-present

*-present

Stephen A. Byrne

54

52

President of Generation and Transmission and Chief Operating Officer-SCE&G

Executive Vice President-SCANA

Executive Vice President-Generation and Transmission-SCETransmission -SCE&G

Executive Vice President-Generation, Nuclear and Fossil Hydro-SCE&G

2011-present

2009-present

2011

2009-2011

Senior Vice President-Generation, Nuclear and Fossil Hydro-SCE&G

2011-present
2009-present
2011
2009-2011
*-2009

Paul V. Fant

60

58

President and Chief Operating Officer-CGT

Senior Vice President-SCANA

*-present
*-present
D. Russell Harris49
President of Gas Operations-SCE&G
President and Chief Operating Officer-PSNC Energy
Senior Vice President-Transmission Services-SCE&G

President-Gas Distribution-SCANA
Senior Vice President-SCANA

2013-present
*-present

2008-present

*-2007

2013-present
2012-2013

W. Keller Kissam

47

45

President of Retail Operations-SCE&G

Senior Vice President-SCANA

Senior Vice President-Retail Electric-SCE&G

Vice President-Electric Operations-SCE&G

2011-present

2011-present

2011

*-2011

Ronald T. Lindsay

63

61

Senior Vice President, General Counsel and Assistant Secretary

Executive Vice President, General Counsel and Secretary of Bowater
Incorporated, Greenville, South Carolina

2009-present

*-2008

-present 

Charles B. McFadden

69

67

Senior Vice President-Governmental Affairs and Economic
Development-SCANA Development-
SCANA Services

Senior Vice President-SCANA

*-present

*-present

Martin K. Phalen

59

57

Senior Vice President-Administration-SCANA

Vice President-Gas Operations-SCE&G

2012-present

*-2012



*  Indicates position held at least since March 1, 2007.

262009.



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Table of Contents

PART II


ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

COMMON STOCK INFORMATION

SCANA Corporation:

Price Range (New York Stock Exchange(NYSE Composite Listing):

 

 

2011

 

2010

 

 

 

4th Qtr.

 

3rd Qtr.

 

2nd Qtr.

 

1st Qtr.

 

4th Qtr.

 

3rd Qtr.

 

2nd Qtr.

 

1st Qtr.

 

High

 

$

45.48

 

$

41.58

 

$

42.20

 

$

42.83

 

$

41.97

 

$

40.82

 

$

39.99

 

$

38.17

 

Low

 

$

38.49

 

$

34.64

 

$

38.16

 

$

37.86

 

$

40.03

 

$

35.23

 

$

34.73

 

$

34.23

 

 2013 2012
 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr. 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr.
High$48.15
 $52.93
 $54.41
 $51.23
 $49.64
 $50.34
 $48.24
 $46.12
Low$44.75
 $45.72
 $47.22
 $45.57
 $44.71
 $47.18
 $43.32
 $43.56
SCANA common stock trades on The New York Stock Exchange,the NYSE using the ticker symbol SCG. Newspaper stock listings use the name SCANA.  At February 20, 20122014 there were 130,295,890141,144,841 shares of SCANA common stock outstanding which were held by approximately 29,13428,121 shareholders of record. For a summary of equity securities issuable under SCANA’s compensation plans at December 31, 2011,2013, see Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

SCANA declared quarterly dividends on its common stock of $.485$.5075 per share in 20112013 and $.475$.495 per share in 2010.2012. On February 15, 2012,20, 2014, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.495$.525 per share, an increase of 2.1%approximately 3.5%. The newnext quarterly dividend is payable April 1, 20122014 to shareholders of record on March 9, 2012.10, 2014.  For a discussion of provisions that could limit the payment of cash dividends, see Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS under Liquidity and Capital Resources-Financing Limits and Related Matters and Note 3 to the consolidated financial statements for SCANA.

SCE&G:

All of SCE&G’s common stock is owned by SCANA, and no established public trading market exists for SCE&G common stock. During 20112013 and 2010,2012, SCE&G declared quarterly dividends on its common stock in the following amounts:

Declaration Date

Amount

Declaration Date

Amount

February 11, 2010

$

45.0 million

February 11, 2011

$

49.0 million

May 6, 2010

46.0 million

April 21, 2011

47.5 million

July 29, 2010

49.0 million

August 11, 2011

49.0 million

October 27, 2010

52.4 million

October 26, 2011

38.0 million

Declaration Date Amount Declaration Date Amount
February 15, 2012 $51.6 million February 20, 2013 $62.2 million
May 3, 2012 52.3 million April 25, 2013 62.0 million
August 2, 2012 54.0 million July 31, 2013 65.8 million
October 24, 2012 44.3 million October 31, 2013 60.0 million
On February 15, 2012,20, 2014, SCE&G declared dividends on its common stock of $51.6$62.5 million.

For a discussion of provisions that could limit the payment of cash dividends, see Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS under Liquidity and Capital Resources-Financing Limits and Related Matters and Note 3 to the consolidated financial statements for SCE&G.

27



22




Table of Contents

ITEM 6.  SELECTED FINANCIAL DATA
As of or for the Year Ended December 31, 2013 2012 2011 2010 2009
  (Millions of dollars, except statistics and per share amounts)
SCANA:  
  
  
  
  
Statement of Income Data  
  
  
  
  
Operating Revenues $4,495
 $4,176
 $4,409
 $4,601
 $4,237
Operating Income $910
 $859
 $813
 $768
 $699
Preferred Stock Dividends $
 $
 $
 $
 $9
Income Available to Common Shareholders $471
 $420
 $387
 $376
 $348
Common Stock Data    
  
  
  
Weighted Average Common Shares Outstanding (Millions) 138.7
 131.1
 128.8
 125.7
 122.1
Basic Earnings Per Share $3.40
 $3.20
 $3.01
 $2.99
 $2.85
Diluted Earnings Per Share $3.39
 $3.15
 $2.97
 $2.98
 $2.85
Dividends Declared Per Share of Common Stock $2.03
 $1.98
 $1.94
 $1.90
 $1.88
Balance Sheet Data      
  
  
Utility Plant, Net $11,643
 $10,896
 $10,047
 $9,662
 $9,009
Total Assets $15,164
 $14,616
 $13,534
 $12,968
 $12,094
Total Equity $4,664
 $4,154
 $3,889
 $3,702
 $3,408
Short-term and Long-term Debt $5,825
 $5,744
 $5,306
 $4,909
 $4,846
Other Statistics    
  
  
  
Electric:    
  
  
  
Customers (Year-End) 678,273
 669,966
 664,196
 660,580
 654,766
Total sales (Million kWh) 22,313
 23,879
 24,188
 24,884
 23,104
Generating capability-Net MW (Year-End) 5,237
 5,533
 5,642
 5,645
 5,611
Territorial peak demand-Net MW 4,574
 4,761
 4,885
 4,735
 4,557
Regulated Gas:      
  
  
Customers, excluding transportation (Year-End) 837,232
 818,983
 803,644
 794,841
 782,192
Sales, excluding transportation (Thousand Therms) 921,533
 798,978
 812,416
 931,879
 832,931
Transportation customers (Year-End) 496
 499
 492
 491
 482
Transportation volumes (Thousand Therms) 1,729,399
 1,559,542
 1,585,202
 1,546,234
 1,388,096
Retail Gas Marketing:      
  
  
Retail customers (Year-End) 454,104
 449,144
 455,258
 464,123
 455,198
Firm customer deliveries (Thousand Therms) 382,728
 310,442
 341,554
 402,583
 347,324
Nonregulated interruptible customer deliveries (Thousand Therms) 1,928,266
 1,981,085
 1,845,327
 1,728,161
 1,628,942
           
SCE&G:    
  
  
  
Statement of Income Data    
  
  
  
Operating Revenues $2,845
 $2,809
 $2,819
 $2,815
 $2,569
Operating Income $737
 $717
 $654
 $604
 $547
Net Income $391
 $352
 $316
 $304
 $288
Net Income Attributable to Noncontrolling Interest $11
 $11
 $10
 $14
 $7
Preferred Stock Dividends $
 $
 $
 $
 $9
Earnings Available to Common Shareholder $380
 $341
 $306
 $290
 $272
Balance Sheet Data  
  
  
  
  
Utility Plant, Net $10,048
 $9,375
 $8,588
 $8,198
 $7,595
Total Assets $12,700
 $12,104
 $11,037
 $10,574
 $9,813
Total Equity $4,489
 $4,043
 $3,773
 $3,541
 $3,259
Short-term and Long-term Debt $4,306
 $4,171
 $3,753
 $3,440
 $3,430
Other Statistics    
  
  
  
Electric:    
  
  
  
Customers (Year-End) 678,338
 670,030
 664,273
 660,642
 654,830
Total sales (Million kWh) 22,327
 23,899
 24,200
 24,887
 23,107
Generating capability-Net MW (Year-End) 5,237
 5,533
 5,642
 5,645
 5,611
Territorial peak demand-Net MW 4,574
 4,761
 4,885
 4,735
 4,557
Regulated Gas:      
  
  
Customers, excluding transportation (Year-End) 329,179
 322,419
 316,683
 313,346
 309,687
Sales, excluding transportation (Thousand Therms) 457,119
 412,163
 407,073
 447,057
 399,752
Transportation customers (Year-End) 173
 166
 155
 148
 130
Transportation volumes (Thousand Therms) 155,190
 260,215
 192,492
 190,931
 217,750


23

As of or for the Year Ended December 31,

 

2011

 

2010

 

2009

 

2008

 

2007

 

 

 

(Millions of dollars, except statistics and per share amounts)

 

SCANA:

 

 

 

 

 

 

 

 

 

 

 

Statement of Income Data

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

 

$

4,409

 

$

4,601

 

$

4,237

 

$

5,319

 

$

4,621

 

Operating Income

 

$

813

 

$

768

 

$

699

 

$

710

 

$

633

 

Other Expense

 

$

(258

)

$

(233

)

$

(175

)

$

(176

)

$

(153

)

Preferred Stock Dividends

 

$

 

$

 

$

(9

)

$

(7

)

$

(7

)

Income Available to Common Shareholders

 

$

387

 

$

376

 

$

348

 

$

346

 

$

320

 

Common Stock Data

 

 

 

 

 

 

 

 

 

 

 

Weighted Average Common Shares Outstanding (Millions)

 

128.8

 

125.7

 

122.1

 

117.0

 

116.7

 

Basic Earnings Per Share

 

$

3.01

 

$

2.99

 

$

2.85

 

$

2.95

 

$

2.74

 

Diluted Earnings Per Share

 

$

2.97

 

$

2.98

 

$

2.85

 

$

2.95

 

$

2.74

 

Dividends Declared Per Share of Common Stock

 

$

1.94

 

$

1.90

 

$

1.88

 

$

1.84

 

$

1.76

 

Balance Sheet Data

 

 

 

 

 

 

 

 

 

 

 

Utility Plant, Net

 

$

10,047

 

$

9,662

 

$

9,009

 

$

8,305

 

$

7,538

 

Total Assets

 

$

13,534

 

$

12,968

 

$

12,094

 

$

11,502

 

$

10,165

 

Total Equity

 

$

3,889

 

$

3,702

 

$

3,408

 

$

3,045

 

$

2,960

 

Short-term and Long-term Debt

 

$

5,306

 

$

4,909

 

$

4,846

 

$

4,698

 

$

3,852

 

Other Statistics

 

 

 

 

 

 

 

 

 

 

 

Electric:

 

 

 

 

 

 

 

 

 

 

 

Customers (Year-End)

 

664,196

 

660,580

 

654,766

 

649,571

 

639,258

 

Total sales (Million KWh)

 

24,188

 

24,884

 

23,104

 

24,284

 

24,885

 

Generating capability-Net MW (Year-End)

 

5,642

 

5,645

 

5,611

 

5,695

 

5,749

 

Territorial peak demand-Net MW

 

4,885

 

4,735

 

4,557

 

4,789

 

4,926

 

Regulated Gas:

 

 

 

 

 

 

 

 

 

 

 

Customers, excluding transportation (Year-End)

 

803,644

 

794,841

 

782,192

 

774,502

 

759,336

 

Sales, excluding transportation (Thousand Therms)

 

812,416

 

931,879

 

832,931

 

848,568

 

823,976

 

Transportation customers (Year-End)

 

492

 

491

 

482

 

474

 

446

 

Transportation volumes (Thousand Therms)

 

1,585,202

 

1,546,234

 

1,388,096

 

1,366,675

 

1,369,684

 

Retail Gas Marketing:

 

 

 

 

 

 

 

 

 

 

 

Retail customers (Year-End)

 

455,258

 

464,123

 

455,198

 

459,250

 

484,565

 

Firm customer deliveries (Thousand Therms)

 

341,554

 

402,583

 

347,324

 

356,288

 

340,743

 

Nonregulated interruptible customer deliveries (Thousand Therms)

 

1,845,327

 

1,728,161

 

1,628,942

 

1,526,933

 

1,548,878

 

SCE&G:

 

 

 

 

 

 

 

 

 

 

 

Statement of Income Data

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

 

$

2,819

 

$

2,815

 

$

2,569

 

$

2,816

 

$

2,481

 

Operating Income

 

$

654

 

$

604

 

$

547

 

$

559

 

$

498

 

Other Expense

 

$

(198

)

$

(170

)

$

(119

)

$

(122

)

$

(117

)

Preferred Stock Dividends

 

$

 

$

 

$

(9

)

$

(7

)

$

(7

)

Earnings Available to Common Shareholders

 

$

306

 

$

290

 

$

272

 

$

273

 

$

245

 

Balance Sheet Data

 

 

 

 

 

 

 

 

 

 

 

Utility Plant, Net

 

$

8,588

 

$

8,198

 

$

7,595

 

$

6,905

 

$

6,202

 

Total Assets

 

$

11,037

 

$

10,574

 

$

9,813

 

$

9,052

 

$

7,977

 

Total Equity

 

$

3,773

 

$

3,541

 

$

3,259

 

$

2,799

 

$

2,711

 

Short-term and Long-term Debt

 

$

3,753

 

$

3,440

 

$

3,430

 

$

3,320

 

$

2,593

 

Other Statistics

 

 

 

 

 

 

 

 

 

 

 

Electric:

 

 

 

 

 

 

 

 

 

 

 

Customers (Year-End)

 

664,273

 

660,642

 

654,830

 

649,636

 

639,312

 

Total sales (Million KWh)

 

24,200

 

24,887

 

23,107

 

24,287

 

24,888

 

Generating capability-Net MW (Year-End)

 

5,642

 

5,645

 

5,611

 

5,695

 

5,749

 

Territorial peak demand-Net MW

 

4,885

 

4,735

 

4,557

 

4,789

 

4,926

 

Regulated Gas:

 

 

 

 

 

 

 

 

 

 

 

Customers, excluding transportation (Year-End)

 

316,683

 

313,346

 

309,687

 

307,074

 

302,469

 

Sales, excluding transportation (Thousand Therms)

 

407,073

 

447,057

 

399,752

 

416,075

 

407,204

 

Transportation customers (Year-End)

 

155

 

148

 

130

 

120

 

115

 

Transportation volumes (Thousand Therms)

 

192,492

 

190,931

 

217,750

 

64,034

 

27,113

 

28




Table of Contents

SCANA CORPORATION

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45

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48

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53

54

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57

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29


24




Table of Contents

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

SCANA, through its wholly-owned regulated subsidiaries, is primarily engaged in the generation, transmission, distribution and sale of electricity in parts of South Carolina and in the purchase, transmission and sale of natural gas in portions of North Carolina and South Carolina. Through a wholly-owned nonregulated subsidiary, SCANA markets natural gas to retail customers in Georgia and to wholesale customers primarily in the southeast. Other wholly- ownedwholly-owned nonregulated subsidiaries provide fiber optic and other telecommunications services and provide service contracts to homeowners on certain home appliances and heating and air conditioning units. A service company subsidiary of SCANA provides administrative, management and other services to SCANA and its subsidiaries.

The following map indicates areas where the Company’s significant business segments conduct their activities, as further described in this overview section.

The following percentages reflect revenues and net income available to common shareholders earned by the Company’s regulated and nonregulated businesses (including the holding company) and the percentage of total assets held by them.

 

 

2011

 

2010

 

2009

 

 

 

 

 

 

 

 

 

% of Revenues

 

 

 

 

 

 

 

Regulated

 

74

%

73

%

73

%

Nonregulated

 

26

%

27

%

27

%

 

 

 

 

 

 

 

 

% of Income Available to Common Shareholders

 

 

 

 

 

 

 

Regulated

 

97

%

96

%

96

%

Nonregulated

 

3

%

4

%

4

%

 

 

 

 

 

 

 

 

% of Assets

 

 

 

 

 

 

 

Regulated

 

94

%

95

%

94

%

Nonregulated

 

6

%

5

%

6

%

30

 2013
 2012
 2011
Revenues   
  
Regulated75% 77% 74%
Nonregulated25% 23% 26%
Net Income     
Regulated97% 99% 97%
Nonregulated3% 1% 3%
Assets     
Regulated95% 95% 94%
Nonregulated5% 5% 6%


25




Table of Contents

Key Earnings Drivers and Outlook

During 2011,2013, economic growth showed modest signs of improvementcontinued to improve in the southeast. Significant industrial announcements were made in the Company’s South Carolina and North Carolina service territoryterritories during the year.year, and announcements made in previous years began to materialize. In addition, residentialthe Port of Charleston continues to see increased traffic, with container volume up 5.7% over 2012.  Residential and commercial customer growth rates in the Company’s regulated businesses were positive, though customer usage by existing customers continued to decline.also remained positive.  Unemployment rates for the states in which the Company primarily provides service also showed some improvement,improved in 2013, though unemployment remains high and continuessuch rates improved in part due to slowpeople leaving the pace of economic recovery inworkforce. Nationwide, the Southeast.

Unemployment (seasonally adjusted)

 

United States

 

Georgia

 

North Carolina

 

South Carolina

 

 

 

 

 

 

 

 

 

 

 

December 31, 2011 (preliminary)

 

8.5

%

9.7

%

9.9

%

9.5

%

December 31, 2010

 

9.4

%

10.4

%

9.8

%

10.9

%

civilian labor force participation rate was 62.8% at December 31, 2013, matching a 35-year low.

Unemployment (seasonally adjusted)United States Georgia North Carolina South Carolina
December 31, 2013 (preliminary)6.7% 7.4% 6.9% 6.6%
December 31, 20127.8% 8.7% 9.4% 8.6%
December 31, 20118.9% 9.4% 10.4% 9.6%
Over the next five years, key earnings drivers for the Company will be additions to rate base at its regulated subsidiaries, consisting primarily of capital expenditures for new generating capacity, environmental facilities and system expansion. Other factors that will impact future earnings growth include the regulatory environment, customer growth and usage in each of the regulated utility businesses, earnings in the natural gas marketing business in Georgia and the level of growth of operation and maintenance expenses and taxes.

Electric Operations

The electric operations segment is comprised of the electric operations of SCE&G, GENCO and Fuel Company, and is primarily engaged in the generation, transmission, distribution and sale of electricity in South Carolina. At December 31, 2011,2013, SCE&G provided electricity to approximately 664,000678,000 customers in an area covering nearly 17,000 square miles. GENCO owns a coal-fired generating station and sells electricity solely to SCE&G. Fuel Company acquires, owns, and provides financing for and sells at cost to SCE&G’s&G nuclear fuel, certain fossil fuels and emission and other environmental allowances.

Operating results for electric operations are primarily driven by customer demand for electricity, rates allowed to be charged to customers and the ability to control growth in costs. Through 2013, the effect of weather on operating results was largely mitigated by the eWNA; however, the eWNA was discontinued pursuant to SCPSC order effective with the first billing cycle of January 2014. Embedded in the rates charged to customers is an allowed regulatory return on equity. SCE&G’s allowed return on equity is 10.7%in 2013 was 10.25% for non-BLRA expenditures, and 11.0% for BLRA-related expenditures. As further described in Note 2 to the consolidated financial statements, SCE&G's allowed return on equity for non-BLRA expenditures was 10.7% prior to 2013. Demand for electricity is primarily affected by weather, customer growth and the economy.  SCE&G is able to recover the cost of fuel used in electric generation through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.


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's 2012 IRP identified six coal-fired units that SCE&G has subsequently retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (2012 summer rating) of 730 MW. As of December 31, 2013, three of these units have been retired. For additional information, see Note 1 and Note 2 to the consolidated financial statements.

New Nuclear Construction

SCE&G and Santee Cooper are parties to construction and operating agreements in which they agreed to be joint owners, and share operating costs and generation output, ofis constructing two 1,117-MW1,250 MW (1,117 MW, net) nuclear generation units to be constructed at the site of Summer Station,Station. SCE&G will jointly own the New Units with Santee Cooper, and SCE&G will be responsible for 55 percent of the cost of and receiving 55 percent ofreceive the output andfrom the New Units in proportion to its share of ownership, with Santee Cooper responsible for and receiving the remaining 45 percent.share. SCE&G's current ownership share in the New Units is 55%. Under these agreements,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. Under the terms of this agreement, SCE&G will have the primary responsibility for oversight of the construction ofacquire a one percent ownership interest in the New Units at the commercial operation date of Unit 2, will acquire an additional two percent ownership interest no later than the first anniversary of such commercial operation date, and will be responsible foracquire the final

26



two percent no later than the second anniversary of such commercial operation date. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units as they come online.

SCE&G, on behalf of itself and as agent for Santee Cooper, has entered into the EPC Contract with the Consortium for the design and construction ofto third parties until the New Units.  Units are complete.


SCE&G’s&G expects Unit 2 to be placed in service in the fourth quarter of 2017 or the first quarter of 2018, with Unit 3's in-service date approximately 12 months later. SCE&G's share of the estimated cash outlays (future value, excluding AFC) for its current 55% ownership share totals approximately $6$5.4 billion for plant costs and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC. The successful completionIn addition, under the terms of the New Units would resultagreement previously described, SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost of the percentage conveyed as of the date of conveyance, which SCE&G estimates will be approximately $500 million for the entire 5% interest.

Significant recent developments in new nuclear construction include the following:

In the first quarter of 2013, initial pouring of the Unit 2 nuclear island basemat was completed. The basemat provides a substantial increasefoundation for the containment vessel, shield building and auxiliary building that make up the nuclear island. The Unit 3 nuclear island basemat was completed in the Company’s utility plantfourth quarter of 2013.

In April 2013, the 500-ton CR-10 module was set on the Unit 2 basemat. CR-10 supports the containment vessel. Construction of Unit 3's CR-10 module is currently underway.

In May 2013, the containment vessel bottom head for Unit 2 was put in service.  Financingplace. The containment vessel will house numerous reactor system components, such as the reactor vessel, steam generator and managingpressurizer. Work continues in building containment vessel rings that will be placed on the containment vessel bottom head for Unit 2.

In September 2013, the reactor vessel cavity for Unit 2 (CA-04 module) was placed in the containment vessel bottom head. The reactor vessel cavity will house the reactor vessel, which in turn will house the fuel assemblies. The reactor vessel for Unit 2 is on-site.

Fabrication has begun for Unit 2's steam generator and refueling canal module (CA-01 module) that will be located inside the containment vessel.

Ring 1 of the Unit 2 containment vessel is scheduled to be placed on the containment vessel bottom head in the second quarter 2014. Ring 2 is scheduled to be placed in the fourth quarter of 2014.

While progress has been made with production, quality assurance and quality control issues, the schedule for fabrication of sub-modules at the contractor facility remains a focus area for the project.

During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules. SCE&G anticipates that this revised schedule and the cost estimate at completion for all non-firm and fixed scopes of work will be finalized in the third quarter of 2014. SCE&G plans to reevaluate and reschedule its owners cost estimates and cash flow requirements in light of the new schedule.

For additional information on these plants, together with continuing environmental construction projects, represents a significant challengeand other matters, see New Nuclear Construction Matters herein and Note 2 and Note 10 to the Company.

consolidated financial statements.

Environmental
As previously reported, SCE&G has been advisedpart of the President's Climate Action Plan and by Santee Cooper that itPresidential Memorandum issued June 25, 2013, the EPA was directed to issue a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The rule became final on January 8, 2014 and requires all new fossil fuel-fired power plants to meet the carbon dioxide emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without carbon capture and sequestration capabilities. The Company is reviewing certain aspects of its capital improvement program and long-term power supplyevaluating the final rule, but does not plan including the level of its participationto construct new coal-fired units in the near future. The Memorandum also directed the EPA to issue standards, regulations, or guidelines for existing units by June 1, 2014, to be made final no later than June 1, 2015.

The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. New Units.  Santee Cooper has entered into a letter of intent with Duke that may result in Duke acquiring a portion of Santee Cooper’s ownership interestfederal effluent limitation guidelines for steam electric generating units were published in the New Units.

Federal Register on


27



June 7, 2013, and the ELG Rule is expected to be finalized May 22, 2014. The Consortium has recently performed an impact study, at SCE&G’s request, relatedEPA expects compliance as soon as possible after July 2017 but no later than July 2020. Additionally, the EPA is expected to various costissue a rule that modifies requirements for existing cooling water intake structures in early 2014, and timing alternatives arising from the delay in the issuance date of the COL from mid-2011, which was the date assumed when the EPC Contract was signed in 2008,Congress is expected to consider further amendments to the early-2012 issuance date currently anticipated by SCE&G.  SCE&G has recently

31

CWA.



Table of Contents

informed the Consortium that it intendsIn response to pursue the alternative that would delay the substantial completion date of the first New Unit and accelerate the substantial completion datea federal court order to establish a definite timeline for the second New Unit and has also begun discussions concerning the update of cash flow forecasts and construction schedules on that basis.

In December 2011, the NRC granted final design certification to Westinghouse for the AP1000 nuclear reactor, which is the reactor to be used for the New Units.  This certification is a necessary step before the NRC can issue a COL for the New Units.  In October 2011, the NRC conducted a mandatory hearing regarding the issuance of a COL for the New Units.  This hearing followed the August 2011 completion of the FSER, in which the NRC staff concluded there were no safety aspects that would preclude issuing the COL, and the April 2011 completion of the FEIS, in which the NRC and the USACE concluded there were no environmental impacts that would preclude issuing the COL.

See additional discussion at OTHER MATTERS - Nuclear Generation.

Environmental

Significant federal legislative initiatives related to energy were unsuccessful in 2011, and the Company expects such legislative initiatives will be hampered through 2012, due to each chamber of Congress being controlled by different political parties. The EPA, however, did issue new rules in 2011 related to air quality, including CSAPR and MATS, which require reductions in

power plant emissions of sulfur dioxide, nitrogen oxide and mercury, among other substances.  Though implementation of CSAPR was stayed by the United States Court of Appeals for the District of Columbia pending judicial review, the Company cannot predict the outcome that judicial review will have on the rule’s implementation. In 2012, additional significant regulatory initiatives byCCR rule, the EPA and other federal agencieshas said it will likely proceed. These initiatives may require the Company to build or otherwise acquire generating capacity from energy sources that exclude fossil fuels, nuclear or hydro facilities (for example, under an RES). It is also possible that new initiatives will be introduced to reduce carbon dioxide and other greenhouse gas emissions. The Company cannot predict whether such initiatives will be enacted, and if they are, the conditions they would impose on utilities.

The EPA has stated its intention to propose, in late 2012,issue new federal regulations affecting the management and disposal of CCR,CCRs, such as ash.ash, by December 14, 2014. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO.

The EPA is also expectedabove environmental initiatives and other similar issues are described in Environmental Matters herein and in Note 10 to issue regulations during 2012 for cooling water intake structures to meet BACT at existing power generating stations.  Whilethe consolidated financial statements. Unless otherwise noted, the Company cannot predict how extensivewhen regulatory rules or legislative requirements for any of these initiatives will become final, if at all, or what conditions they may impose on the regulations will be, theCompany, if any. The Company believes that any additional costs imposed by such regulations would be recoverable through rates.


Gas Distribution

The gas distribution segment, comprised of the local distribution operations of SCE&G and PSNC Energy, is primarily engaged in the purchase, transportation and sale of natural gas to retail customers in portions of NorthSouth Carolina and SouthNorth Carolina. At December 31, 20112013 this segment provided natural gas to approximately 804,000838,000 customers in areas covering 34,600 square miles.

Operating results for gas distribution are primarily influenced by customer demand for natural gas, rates allowed to be charged to customers and the ability to control growth in costs. Embedded in the rates charged to customers is an allowed regulatory return on equity.

equity of 10.25% for SCE&G and 10.60% for PSNC Energy.

Demand for natural gas is primarily affected by weather, customer growth, the economy and for commercial and industrial customers, the availability and price of alternate fuels. Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and will impact the Company’s ability to retain large commercial and industrial customers. One effect ofIn addition, the sluggish economy has been an overall decrease in demand for natural gas which, coupled with discoveriesproduction of shale gas in the United States has resulted in significantly lower prices for this commodity, in 2010 and 2011.  Low natural gas commoditysuch prices are expected to continue in 2012 and beyond.

32

for the foreseeable future.



Table of Contents

Retail Gas Marketing

SCANA Energy, a division of SEMI, comprises the retail gas marketing segment. This segment markets natural gas to approximately 455,000454,000 customers throughout Georgia (as of December 31, 2011,2013, and includes approximately 80,00068,000 customers in its regulated division described below). SCANA Energy’s total customer base represents an approximate 30% share of the customers in Georgia’s deregulated natural gas market. SCANA Energy remains the second largest natural gas marketer in the state. SCANA Energy’s competitors include an affiliate of a large energy company with experience in Georgia’s energy market, as well as several electric membership cooperatives. SCANA Energy’s ability to maintain its market share depends on the prices it charges customers relative to the prices charged by its competitors, its ability to continue to provide high levels of customer service and other factors.

In addition, SCANA Energy's operating results are highly sensitive to weather. This market has matured in the last decade, resulting in lower margins and enhanced competition for customers.

As Georgia’s regulated provider, SCANA Energy provides service at rates approved by the GPSC to low-income customers and to customers unable to obtain or maintain natural gas service from other marketers at rates approved by the GPSC..  SCANA Energy receives funding from theGeorgia's Universal Service Fund to offset some of the bad debt associated with the low-income group. In third quarter 2013, SCANA Energy’s contract to serve as Georgia’s regulated provider of natural gas has been renewedwas extended by the GPSC through August 31, 2014.2015.  SCANA Energy files financial and other information periodically with the GPSC, and such information is available at www.psc.state.ga.us (which is not intended as an active hyperlink; the information on the GPSC website is not part of this or any other report filed with the SEC).


28



SCANA Energy and certain of SCANA’s other natural gas distribution and marketing segments maintain gas inventory and also utilize forward contracts and other financial instruments, including commodity swaps and futures contracts, to manage their exposure to fluctuating commodity natural gas prices. See Note 6 to the consolidated financial statements. As a part of this risk management process, at any given time, a portion of SCANA’s projected natural gas needs has been purchased or otherwise placed under contract. Since SCANA Energy operates in a competitive market, it may be unable to sustain its current levels of customers and/or pricing, thereby reducing expected margins and profitability. Further, there can be no assurance that Georgia’s gas delivery regulatory framework will remain unchanged as dynamic market conditions evolve.


Energy Marketing

The divisions of SEMI excluding SCANA Energy comprise the energy marketing segment. This segment markets natural gas primarily in the southeast and provides energy-related risk management services to customers.

The operating results for energy marketing are primarily influenced by customer demand for natural gas and the ability to control growth of costs. Demand for natural gas is primarily affected by the price of alternate fuels and customer growth. In addition, certain pipeline capacity available for Energy Marketing to serve industrial and other customers is dependent upon the market share held by SCANA Energy in the retail market.



RESULTS OF OPERATIONS

 

 

2011

 

2010

 

2009

 

Basic earnings per share

 

$

3.01

 

$

2.99

 

$

2.85

 

Diluted earnings per share

 

$

2.97

 

$

2.98

 

$

2.85

 

Cash dividends declared (per share)

 

$

1.94

 

$

1.90

 

$

1.88

 

 2013 2012 2011
Basic earnings per share$3.40
 $3.20
 $3.01
Diluted earnings per share$3.39
 $3.15
 $2.97
Cash dividends declared (per share)$2.03
 $1.98
 $1.94

·

2011

2013 vs 2010

2012

Basic earnings per share increased in 2011 due to higher electric and gas margins. These margin increases were partially offset by higher operation and maintenance expenses, higher depreciation expense, higher property taxes, dilution from additional shares outstanding and higher interest expense, as further described below.

2012 vs 2011Basic earnings per share increased due to higher electric and gas margins and gains on sales of $.42 and lowercommunications towers. These increases were partially offset by higher operating expenses, higher depreciation expense, higher property taxes, dilution from additional shares outstanding and higher interest expense, as further described below.
Diluted earnings per share figures give effect to dilutive potential common stock using the treasury stock method. See Note 1 to the consolidated financial statements.

Electric Operations
Electric Operations is comprised of the electric operations of SCE&G, GENCO and Fuel Company. Electric operations sales margin (including transactions with affiliates) was as follows: 
Millions of dollars 2013 Change 2012 Change 2011
Operating revenues $2,430.5
 (0.9)% $2,453.1
 0.9 % $2,432.2
Less: Fuel used in generation 751.0
 (11.0)% 844.2
 (8.5)% 922.5
       Purchased power 43.0
 53.0 % 28.1
 46.4 % 19.2
Margin $1,636.5
 3.5 % $1,580.8
 6.1 % $1,490.5

29



2013 vs 2012Margin increased primarily due to base rate increases under the BLRA of $.06.$54.2 million and higher electric base rates of $67.3 million approved in the December 2012 rate order. Additionally, pursuant to accounting orders of the SCPSC, 2013's electric margin reflects downward adjustments of $50.1 million to revenue. Such adjustments are fully offset by the recognition within other income of gains realized upon the settlement of certain derivative interest rate contracts, which had been deferred as regulatory liabilities. See Note 2 to the consolidated financial statements.
2012 vs 2011Margin increased primarily by $54.4 million due to an increase in retail electric base rates approved by the SCPSC under the BLRA, by $3.7 million due to customer growth and by $11.0 million due to the expiration of a decrement rider approved in the 2010 retail electric base rate case.

Sales volumes (in GWh) related to the electric margin above, by class, were as follows: 
Classification 2013 Change 2012 Change 2011
Residential 7,571
 
 7,571
 (8.0)% 8,232
Commercial 7,205
 (1.2)% 7,291
 (1.4)% 7,397
Industrial 6,000
 2.8 % 5,836
 (1.7)% 5,938
Other 581
 (0.9)% 586
 2.4 % 572
Total retail sales 21,357
 0.3 % 21,284
 (3.9)% 22,139
Wholesale 955
 (63.2)% 2,595
 26.6 % 2,049
Total Sales 22,312
 (6.6)% 23,879
 (1.3)% 24,188
2013 vs 2012Retail sales volume increased primarily due to customer growth and the effects of weather, partially offset by lower average use. The decrease in wholesale sales is primarily due to the expiration of two customer contracts.
2012 vs 2011Retail sales volume decreased by 983 GWh primarily due to the effects of milder weather. The increase in wholesale sales is primarily due to higher contract utilization by a wholesale customer.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy. Gas Distribution sales margin (including transactions with affiliates) was as follows: 
Millions of dollars 2013 Change 2012 Change 2011
Operating revenues $942.6
 23.2% $765.0
 (9.0)% $840.4
Less: Gas purchased for resale 534.9
 42.8% 374.6
 (19.7)% 466.3
Margin $407.7
 4.4% $390.4
 4.4 % $374.1
2013 vs 2012Margin increased primarily due to the SCPSC-approved increase in base rates under the RSA which became effective with the first billing cycle of November 2012, as well as residential and commercial customer growth and increased industrial usage.
2012 vs 2011Margin at SCE&G increased by $8.3 million due to the SCPSC-approved increases in retail gas base rates under the RSA which became effective with the first billing cycles of November 2011 and 2012. Margin at PSNC Energy increased by $5.1 million primarily due to residential and commercial customer growth and increased industrial sales due to the competitive price of gas versus alternate fuel sources.


30



Sales volumes (in MMBTU) by class, including transportation gas, were as follows: 
Classification (in thousands) 2013 Change 2012 Change 2011
Residential 41,268
 24.4% 33,161
 (9.3)% 36,568
Commercial 28,181
 12.7% 25,001
 (3.0)% 25,772
Industrial 22,319
 4.6% 21,340
 13.6 % 18,782
Transportation gas 42,221
 9.0% 38,736
 13.4 % 34,152
Total 133,989
 13.3% 118,238
 2.6 % 115,274
2013 vs 2012Total sales volumes increased primarily due to customer growth, increased industrial usage and the effects of weather.
2012 vs 2011Residential and commercial sales volume decreased primarily due to milder weather. Industrial and transportation sales volumes increased due to the competitive price of gas versus alternate fuel sources.
Retail Gas Marketing
Retail Gas Marketing is comprised of SCANA Energy which operates in Georgia’s natural gas market. Retail Gas Marketing revenues and net income were as follows: 
Millions of dollars 2013 Change 2012 Change 2011
Operating revenues $465.2
 12.8% $412.5
 (13.8)% $478.8
Net Income 23.8
 * 10.5
 (56.6)% 24.2
*Greater than 100%

2013 vs 2012Changes in operating revenues and net income are due to higher demand in 2013 primarily as a result of milder weather in 2012.
2012 vs 2011Reductions in operating revenues and net income were primarily due to milder weather and a decrease in the number of customers served under the regulated provider program in 2012.
Energy Marketing
Energy Marketing is comprised of the Company’s nonregulated marketing operations, excluding SCANA Energy. Energy Marketing operating revenues and net income were as follows: 
Millions of dollars 2013 Change 2012 Change 2011
Operating revenues $818.5
 22.3% $669.0
 (20.8)% $844.9
Net Income 6.1
 13.0% 5.4
 22.7 % 4.4
2013 vs 2012Operating revenues and net income increased due to higher industrial sales volume and higher market prices.
2012 vs 2011Operating revenues decreased due to lower market prices. Net income increased due to higher consumption.

Other Operating Expenses
Other operating expenses were as follows:
Millions of dollars 2013 Change 2012 Change 2011
Other operation and maintenance $707.5
 2.6% $689.3
 4.8% $657.9
Depreciation and amortization 378.1
 6.2% 356.1
 2.8% 346.3
Other taxes 219.7
 6.1% 207.1
 3.1% 200.8

31



2013 vs 2012Other operation and maintenance expenses increased by $16.7 million due to incremental expenses associated with the December 2012 SCPSC rate order and by $5.7 million due to higher electric generation, transmission and distribution expenses. These increases were partially offset by lower gas margincompensation costs of $.13, higher$10.1 million due to reduced headcount and lower incentive compensation accruals and by other general expenses. Depreciation and amortization expense increased $13.2 million due to the recognition of depreciation expense of $.06,associated with the Wateree Station scrubber which was provided for in the December 2012 SCPSC rate order and due to other net plant additions. Other taxes increased primarily due to higher property taxes of $.06, dilution from additional shares outstanding of $.07 and higher interest expense of $.14.

on net property additions.

·

2012 vs 2011

2010 vs 2009

Basic earnings per shareOther operation and maintenance expenses increased in 2010by $9.3 million due to higher electric margin (excluding the effect of the $17.4generation, transmission and distribution expenses and by $25.0 million adjustment described at “Electric Operations”) of $.60due to higher incentive compensation and higher gas margin of $.15.other benefits. These increases were partially offset by dilution from additional shares outstanding of $.09, higher operating expense of $.32, higher interest expense of $.09, net of preferred stock dividends, and $.11$3.9 million due to the tax benefitlower customer service expenses, including bad debt expense, and related interest income arising from the resolution of an income tax uncertainty in favor of the Company in 2009. In late 2009 SCE&G redeemed for cash all outstanding shares of its cumulative preferred stock.

by $1.6 million due to lower general expenses. Depreciation and amortization expense increased primarily due to net property additions. Other taxes increased primarily due to higher property taxes on net property additions.

Diluted Earnings Per Share

In May 2010, SCANA entered into equity forward contracts for approximately 6.6 million common shares. During periods when the average market price of SCANA’s common stock is above the per share adjusted forward sales price, the

33



Net Periodic Benefit Cost

Table of Contents

Company computes diluted earnings per share giving effect to this dilutive potential common stock utilizing the treasury stock method.

Pension Cost

Pension     Net periodic benefit cost was recorded on the Company’sCompany's income statements and balance sheets as follows:

Millions of dollars

 

2011

 

2010

 

2009

 

Income Statement Impact:

 

 

 

 

 

 

 

Increase in employee benefit costs

 

$

2.6

 

$

1.1

 

 

Other expense (income)

 

0.5

 

(3.9

)

$

(3.7

)

Balance Sheet Impact:

 

 

 

 

 

 

 

Increase in capital expenditures

 

3.9

 

6.0

 

9.8

 

Component of amount receivable from Summer Station co-owner

 

1.2

 

1.7

 

2.7

 

Increase in regulatory asset

 

9.1

 

18.6

 

31.2

 

Total Pension Cost

 

$

17.3

 

$

23.5

 

$

40.0

 

Millions of dollars 2013 Change 2012 Change 2011
Income Statement Impact:          
   Employee benefit costs $15.5
 * $4.0
 53.8% $2.6
   Other expense 1.0
 25.0 % 0.8
 60.0% 0.5
Balance Sheet Impact:          
   Increase in capital expenditures 7.2
 9.1 % 6.6
 69.2% 3.9
   Component of amount receivable from Summer Station co-owner 2.5
 13.6 % 2.2
 83.3% 1.2
   Increase in regulatory asset 5.5
 (63.1)% 14.9
 63.7% 9.1
 Net periodic benefit cost $31.7
 11.2 % $28.5
 64.7% $17.3
* Greater than 100%

Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts included in rates for its retail electric and gas distribution regulated operations. In connection with the SCPSC’sSCPSC's July 2010 electric rate order and November 2010 natural gas RSA order, SCE&G began deferring, as a regulatory asset, all pension cost related to retail electric and gas operations that otherwise would have been charged to expense. TheseEffective in January 2013, in connection with the December 2012 rate order, SCE&G began amortizing previously deferred pension costs willrelated to retail electric operations totaling approximately $63 million over approximately 30 years (see Note 2) and recovering current pension costs related to retail electric operations through a rate rider that may be adjusted annually. Similarly, in connection with the October 2013 RSA order, deferred until such time as future rate recoverypension cost related to gas operations of approximately $14 million is provided for by the SCPSC.

No contributionbeing amortized over approximately 14 years, and effective November 2013, SCE&G is recovering current pension expense related to gas operations through cost of service rates (see Note 2 to the pension trust was necessary, nor did limitations on benefit payments apply, in orconsolidated financial statements). In 2013, such amortizations totaled approximately $2.0 million for any period reported.

electric operations and $0.2 million for gas operations.


Other Income (Expense)
Other income (expense) includes the results of certain incidental activities of regulated subsidiaries and the activities of certain non-regulated subsidiaries. Components of other income (expense) were as follows: 
Millions of dollars 2013 Change 2012 Change 2011
Other income $100.3
 71.2% $58.6
 12.3% $52.2
Other expense (45.5) 8.1% (42.1) 5.3% (40.0)
Total $54.8
 * $16.5
 35.2% $12.2
*Greater than 100%


32



2013 vs 2012Changes in other income were primarily due to the recognition, pursuant to SCPSC accounting orders, of $50.1 million of gains realized upon the 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 regulatory liabilities. Such gain recognition was fully offset by downward adjustments to revenues reflected within electric margin and had no effect on net income. This increase in other income was partially offset by the sales of communications towers that were recorded in 2012 by a non-regulated subsidiary. Changes in other expense were not significant.
2012 vs 2011Changes in other income were primarily due to the sales of communications towers in 2012 by a non-regulated subsidiary. Changes in other expense were not significant.
AFC

AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 3.9%5.8% of income before income taxes in 2011, 5.6%2013, 5.4% in 20102012 and 9.8%3.9% in 2009.

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

 

2011

 

Change

 

2010

 

Change

 

2009

 

Operating revenues

 

$

2,432.2

 

2.5

%

$

2,373.9

 

10.5

%

$

2,148.9

 

Less: Fuel used in generation

 

922.5

 

(2.6

)%

946.7

 

15.1

%

822.3

 

Purchased power

 

19.2

 

12.9

%

17.0

 

1.2

%

16.8

 

Margin

 

$

1,490.5

 

5.7

%

$

1,410.2

 

7.7

%

$

1,309.8

 

·

2011 vs 2010

Margin increased by $49.0 million due to an increase in retail electric base rates approved by the SCPSC under the BLRA and by $34.5 million due to an SCPSC-approved increase in retail electric base rates in July 2010. Also, margin in the first quarter of 2010 was adjusted downward by $17.4 million pursuant to an SCPSC regulatory order in connection with SCE&G’s annual fuel cost proceeding. These increases were partially offset by $12 million due to the effects of weather in 2010 before the implementation of the SCPSC-approved eWNA and by lower customer usage of $8.7 million.

34

2011.



Table of Contents

·

2010 vs 2009

Margin increased by $37.0 million due to higher SCPSC-approved retail electric base rates in July 2010 and by $30.7 million due to an increase in base rates approved by the SCPSC under the BLRA. In addition, margin increased by $54.2 million (net of eWNA after its implementation) due to weather, by $5.8 million due to higher transmission revenue and off-system sales and by $13.6 million due to the adoption of SCPSC-approved lower electric depreciation rates in 2009, the effect of which was offset by a reduction in the recovery of fuel costs (electric revenue). During the first quarter of 2010, the Company deferred $25 million of incremental revenue as a result of the abnormally cold weather in SCE&G’s service territory (see Note 2 to the consolidated financial statements). Also, margin in the first quarter of 2010 was adjusted downward by $17.4 million pursuant to an SCPSC regulatory order issued in connection with SCE&G’s annual fuel cost proceeding. (See also discussion at “Income Taxes”.) Finally, pursuant to the SCPSC-approved retail electric base rate order in 2010, SCE&G adopted an eWNA thereby mitigating the effects of abnormal weather on its margins.

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

Classification

 

2011

 

Change

 

2010

 

Change

 

2009

 

Residential

 

8,232

 

(6.4

)%

8,791

 

11.4

%

7,893

 

Commercial

 

7,397

 

(3.7

)%

7,684

 

4.5

%

7,350

 

Industrial

 

5,938

 

1.3

%

5,863

 

10.1

%

5,324

 

Other

 

572

 

(1.5

)%

581

 

3.4

%

562

 

Total retail sales

 

22,139

 

(3.4

)%

22,919

 

8.5

%

21,129

 

Wholesale

 

2,049

 

4.3

%

1,965

 

(0.5

)%

1,975

 

Total Sales

 

24,188

 

(2.8

)%

24,884

 

7.7

%

23,104

 

·

2011 vs 2010

Total retail sales volumes decreased by 775 GWh due to weather.

·

2010 vs 2009

Total retail sales volumes increased by 1,209 GWh due to weather and by 539 GWh due to higher industrial sales volumes.

Gas Distribution

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

Millions of dollars

 

2011

 

Change

 

2010

 

Change

 

2009

 

Operating revenues

 

$

840.4

 

(14.2

)%

$

979.4

 

3.3

%

$

948.4

 

Less: Gas purchased for resale

 

466.3

 

(22.5

)%

601.7

 

2.8

%

585.1

 

Margin

 

$

374.1

 

(1.0

)%

$

377.7

 

4.0

%

$

363.3

 

·

2011 vs 2010

Margin at SCE&G decreased by $8.2 million due to the SCPSC-approved decrease in retail gas base rates which became effective with the first billing cycle of November 2010. This decrease was partially offset by an increase of $1.8 million due to the SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2011. Margin at PSNC Energy increased $2.9 million due to residential and commercial customer growth.

·

2010 vs 2009

Margin at SCE&G increased by $9.2 million due to the SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2009 and $3.3 million due to increased customer usage. These increases were partially offset by a decrease of $2.2 million due to an SCPSC-approved decrease in retail gas base rates which became effective with the first billing cycle of November 2010. Margin at PSNC Energy increased by $4.0 million primarily due to residential customer growth and improved industrial usage.

35



Table of Contents

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

Classification (in thousands)

 

2011

 

Change

 

2010

 

Change

 

2009

 

Residential

 

36,568

 

(19.2

)%

45,251

 

16.0

%

38,995

 

Commercial

 

25,772

 

(11.0

)%

28,972

 

6.4

%

27,220

 

Industrial

 

18,782

 

(0.4

)%

18,860

 

12.3

%

16,798

 

Transportation gas

 

34,152

 

3.2

%

33,089

 

7.3

%

30,845

 

Total

 

115,274

 

(8.6

)%

126,172

 

10.8

%

113,858

 

·

2011 vs 2010

Residential, commercial and industrial sales volume decreased primarily due to milder weather. Transportation sales volume increased primarily as a result of improved economic conditions and the competitive price of gas versus alternate fuel sources.

·

2010 vs 2009

Residential sales volume increased primarily due to customer growth and weather. Commercial and industrial sales volume increased primarily as a result of improved economic conditions.

Retail Gas Marketing

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

Millions of dollars

 

2011

 

Change

 

2010

 

Change

 

2009

 

Operating revenues

 

$

478.8

 

(13.4

)%

$

552.9

 

6.0

%

$

521.7

 

Income available to common shareholders

 

$

24.2

 

(20.7

)%

$

30.5

 

27.1

%

$

24.0

 

·

2011 vs 2010

Operating revenues decreased as a result of milder weather and lower consumption. Income available to common shareholders decreased due to lower margins, partially offset by lower bad debt and operating expenses.

·

2010 vs 2009

Operating revenues increased as a result of colder than normal weather and higher consumption. Income available to common shareholders increased due to higher margins, partially offset by higher bad debt and operating expenses.

Energy Marketing

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

Millions of dollars

 

2011

 

Change

 

2010

 

Change

 

2009

 

Operating revenues

 

$

844.9

 

(3.3

)%

$

874.1

 

12.5

%

$

776.9

 

Income available to common shareholders

 

$

4.4

 

12.8

%

$

3.9

 

14.7

%

$

3.4

 

·

2011 vs 2010

Operating revenues decreased due to lower market prices. Income available to common shareholders increased due to lower operating expenses, including bad debt.

·

2010 vs 2009

Operating revenues increased due to higher sales volume. Income available to common shareholders increased due to lower operating expenses, partially offset by higher bad debt expense.

Other Operating Expenses

Other operating expenses were as follows:

Millions of dollars

 

2011

 

Change

 

2010

 

Change

 

2009

 

Other operation and maintenance

 

$

657.9

 

(1.8

)%

$

669.9

 

4.7

%

$

639.7

 

Depreciation and amortization

 

346.3

 

3.3

%

335.1

 

6.0

%

316.0

 

Other taxes

 

200.8

 

5.5

%

190.4

 

7.6

%

176.9

 

36



Table of Contents

·

2011 vs 2010

Other operation and maintenance expenses decreased by $7.8 million due to lower customer service expenses, including bad debt expense, and by $4.1 million due to lower incentive compensation and other benefits. These decreases were partially offset by $0.8 million due to higher generation, transmission and distribution expenses. Depreciation and amortization expense increased primarily due to net property additions. Other taxes increased primarily due to higher property taxes.

·

2010 vs 2009

Other operation and maintenance expenses increased by $17.7 million due to higher generation, transmission and distribution expenses, by $10.9 million due to higher incentive compensation and other benefits and by $6.1 million due to higher customer service expenses and general expenses, including bad debt expense. Depreciation and amortization expense increased primarily due to net property additions. Other taxes increased primarily due to higher property taxes.

Other Income (Expense)

Other income (expense) includes the results of certain incidental (non-utility) activities and the activities of certain non-regulated subsidiaries. Components of other income (expense) were as follows:

Millions of dollars

 

2011

 

Change

 

2010

 

Change

 

2009

 

Other income

 

$

52.2

 

(0.9

)%

$

52.7

 

(21.0

)%

$

66.7

 

Other expense

 

(40.0

)

1.3

%

(39.5

)

7.0

%

(36.9

)

Total

 

$

12.2

 

(7.6

)%

$

13.2

 

(55.7

)%

$

29.8

 

·

2011 vs 2010

Changes in other income (expense) were not significant.

·

2010 vs 2009

Total other income (expense) decreased $13.4 million due to decreased interest income. In September 2009, as a result of a favorable decision by the South Carolina Supreme Court, SCE&G was refunded previously contested EIZ Credits of $15.3 million and an additional $14.3 million of interest income. SCE&G recorded a multi-year catch-up adjustment in the third quarter of 2009 of approximately $6.3 million ($4.0 million after federal tax effect) as a reduction in income taxes. The interest income of $14.3 million ($8.8 million after tax effect) was recorded in the third quarter of 2009 within other income.

Interest Expense

Components of interest expense, net of the debt component of AFC, were as follows:

Millions of dollars

 

2011

 

Change

 

2010

 

Change

 

2009

 

Interest on long-term debt, net

 

$

276.6

 

5.9

%

$

261.1

 

14.3

%

$

228.5

 

Other interest expense

 

7.7

 

71.1

%

4.5

 

(10.0

)%

5.0

 

Total

 

$

284.3

 

7.0

%

$

265.6

 

13.7

%

$

233.5

 

Millions of dollars 2013 Change 2012 Change 2011
Interest on long-term debt, net $292.8
 0.9 % $290.2
 4.9 % $276.6
Other interest expense 4.6
 (11.5)% 5.2
 (32.5)% 7.7
Total $297.4
 0.7 % $295.4
 3.9 % $284.3

Interest on long-term debt increased in each year primarily due to increased long-term borrowings over the prior year.borrowings. Other interest expense increased in 2011, and decreased in 2010,2013 and 2012, primarily due to corresponding changesreductions in principal balances outstanding on short-term debt over the respective prior year.

Income Taxes

Income tax expense (and the effective tax rate) increased in 2011 over 2010 primarilyyear and also decreased due to the accelerated amortizationreversal in 2012 of deferred EIZ Creditsinterest which had been accrued in 2011 related to offset undercollected fuel costs in 2010 pursuant to an SCPSC order and an increase in operating income.  Incomea tax expense (and the effective tax rate) decreased in 2010 over 2009 primarily due to the above-mentioned accelerated amortization of EIZ Credits to offset undercollected fuel costs and the accelerated amortization of EIZ Credits in connection with the July 2010 retail electric rate order. (Seeuncertainty that was resolved (see Note 5 to the consolidated financial statements for reconciling differences between incomestatements).


Income Taxes
Income tax expense increased in 2013 over 2012 and statutoryin 2012 over 2011 primarily due to increases in income before taxes. The increase in the effective tax expense.)

37rate in 2013 is principally attributable to lower recognition of EIZ Credits upon the completion of the amortization of certain such credits in 2012.





Table of Contents

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its contractual cash obligations will be met through internally generated funds, the incurrence of additional short- and long-term indebtedness and sales of equity securities. The Company expects that, barring a future impairment of the capital markets, it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future.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 year ended December 31, 20112013 was 2.87.

3.22.

Cash requirements for SCANA’s regulated subsidiaries arise primarily from their operational needs, funding their construction programs and payment of dividends to SCANA. The ability of the regulated subsidiaries to replace existing plant investment, to expand to meet future demand for electricity and gas and to install equipment necessary to comply with environmental regulations, will depend on their ability to attract the necessary financial capital on reasonable terms. Regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and these subsidiaries continue their ongoing construction programs, rate increases will be sought. The future financial position and results of operations of the regulated subsidiaries will be affected by their ability to obtain adequate and timely rate and other regulatory relief.


33



The Company also obtains equity from SCANA’s stock plans. Shares of SCANA common stock are acquired on behalf of participants in SCANA’s Investor Plus Plan and Stock Purchase-Savings Plan through the original issuance of shares, rather than being purchased on the open market. This provided approximately $97$99 million of additional equity during 2011 and is expected to provide approximately $102 million of additional capital in 2012.2013. Due primarily to new nuclear construction plans, the Company anticipates keeping this strategy in place for the foreseeable future. The Company also expects
In addition, on March 5, 2013, SCANA settled all forward sales contracts related to issueits common stock through the issuance of approximately 6.6 million common shares, resulting in 2012 under forward contracts executed in 2010 (and extended by amendment in October 2011).

net proceeds of approximately $196 million.


SCANA’s leverage ratio of long- and short-term debt to capital was approximately 58%56% at December 31, 2011.2013. SCANA has publicly announced its desire to maintain its leverage ratio at levels between 54% and 57%, but SCANA’s ability to achieve and maintain those levelsdo so depends on a number of factors. In the future, if SCANA is not able to achieve and maintain its leverage ratio within the desired range, the Company’s debt ratings may be affected, it may be required to pay higher interest rates on its long- and short-term indebtedness, and its access to the capital markets may be limited.


Capital Expenditures

Cash outlays for property additions and construction expenditures, including nuclear fuel, net of AFC, were $884 million$1.1 billion in 20112013 and are estimated to be $1.4$1.7 billion in 2012.

2014.


The Company’s current estimates of its capital expenditures for construction and nuclear fuel for 2012-2014,2014-2016, which are subject to continuing review and adjustment, are as follows:


Estimated Capital Expenditures

Millions of dollars

 

2012

 

2013

 

2014

 

SCE&G - Normal

 

 

 

 

 

 

 

Generation

 

$

143

 

$

96

 

$

79

 

Transmission & Distribution

 

197

 

217

 

190

 

Other

 

26

 

14

 

21

 

Gas

 

49

 

51

 

57

 

Common

 

14

 

18

 

13

 

Total SCE&G - Normal

 

429

 

396

 

360

 

PSNC Energy

 

57

 

65

 

70

 

Other

 

54

 

41

 

32

 

Total Normal

 

540

 

502

 

462

 

New Nuclear

 

954

 

952

 

727

 

Cash Requirements for Construction

 

1,494

 

1,454

 

1,189

 

Nuclear Fuel

 

44

 

110

 

55

 

Total Estimated Capital Expenditures

 

$

1,538

 

$

1,564

 

$

1,244

 

38

Millions of dollars 2014 2015 2016
SCE&G - Normal  
  
  
Generation $136
 $145
 $112
Transmission & Distribution 230
 280
 258
Other 14
 25
 19
Gas 50
 51
 73
Common 9
 7
 10
Total SCE&G - Normal 439
 508
 472
PSNC Energy 128
 111
 87
Other 79
 58
 42
Total Normal 646
 677
 601
New Nuclear (including transmission) 950
 905
 667
Cash Requirements for Construction 1,596
 1,582
 1,268
Nuclear Fuel 67
 30
 147
Total Estimated Capital Expenditures $1,663
 $1,612
 $1,415

Estimated capital expenditures for Nuclear Fuel in 2016 include approximately $53 million, which is SCE&G's share of nuclear fuel it acquired in 2013. This fuel has been recorded in utility plant and the corresponding liability has been recorded in long-term debt on the consolidated balance sheet.


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Table of Contents

The Company’s contractual cash obligations as of December 31, 20112013 are summarized as follows:

Contractual Cash Obligations

 

 

Payments due by periods

 

Millions of dollars

 

Total

 

Less than
1 year

 

1 - 3 years

 

4 - 5 years

 

More than
5 years

 

Long- and short-term debt, including interest

 

$

10,477

 

$

1,216

 

$

1,031

 

$

547

 

$

7,683

 

Capital leases

 

13

 

4

 

6

 

3

 

 

Operating leases

 

56

 

11

 

16

 

1

 

28

 

Purchase obligations

 

4,367

 

984

 

2,307

 

412

 

664

 

Other commercial commitments

 

4,724

 

1,062

 

1,587

 

912

 

1,163

 

Total

 

$

19,637

 

$

3,277

 

$

4,947

 

$

1,875

 

$

9,538

 

  Payments due by periods
Millions of dollars Total 
Less than
1 year
 1 - 3 years 4 - 5 years 
More than
5 years
Long- and short-term debt, including interest $10,954
 $713
 $885
 $1,243
 $8,113
Capital leases 17
 3
 10
 2
 2
Operating leases 41
 7
 12
 3
 19
Purchase obligations 3,938
 2,067
 1,648
 221
 2
Other commercial commitments 4,397
 886
 1,700
 998
 813
Total $19,347
 $3,676
 $4,255
 $2,467
 $8,949
Included in the table above in purchase obligations is SCE&G’s portion of a contractual agreement for the design and construction of the New Units at the Summer Station site. SCE&G expects to be a joint owner and share operating costs and generation output of the New Units, with SCE&G accountingcurrently responsible for 55 percent of the cost and receiving 55 percent of the output, and the other joint owner(s)owner (or owners) the remaining 45 percent. SCE&G’s estimated projected costs for the two additional units, in future dollars and excluding AFC, are summarized below. To the extent that actual contracts were put in place by December 31, 2011, obligations arising from these contracts areAlso included in the purchase obligations withintable above is the Contractual Cash Obligations table above.

Future Value
Millions of
dollars

 

2012

 

2013

 

2014

 

2015

 

2016

 

After 2016

 

Total Project Cash Outlay

 

$

804

 

$

825

 

$

558

 

$

575

 

$

367

 

$

232

 

estimated $500 million SCE&G expects it will cost to acquire an additional 5% ownership in the New Units as further described in New Nuclear Construction Matters.


Also included in purchase obligations are customary purchase orders under which the Company has the option to utilize certain vendors without the obligation to do so. The Company may terminate such arrangements without penalty.


Other commercial commitments includes estimated obligations under forward contracts for natural gas purchases. Forward contracts for natural gas purchases include customary “make-whole” or default provisions, but are not considered to be “take-or-pay” contracts. Certain of these contracts relate to regulated businesses; therefore, the effects of such contracts on fuel costs are reflected in electric or gas rates.  Other commercial commitments also includes a “take-and-pay” contract for natural gas which expires in 2019 and estimated obligations for coal and nuclear fuel purchases.

In addition to the contractual cash obligations above, the Company sponsors a noncontributory defined benefit pension plan and an unfunded health care and life insurance benefit plan for retirees. The pension plan is adequately funded under current regulations, and no significant contributions are anticipated until after 2012.for the foreseeable future. Cash payments under the postretirement health care and life insurance benefit plan were $12.2$9.2 million in 2011,2013, and such annual payments are expected to be the same or increase up to $14.0$14.7 million in the future.

In addition, the Company is party to certain NYMEX natural gas futures contracts for which any unfavorable market movements are funded in cash. These derivatives are accounted for as cash flow hedges and their effects are reflected within other comprehensive income until the anticipated sales transactions occur. See further discussion at Item 7A. Quantitative and Qualitative Disclosures About Market Risk.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. At December 31, 2011,2013, the Company had posted $15.4$6.4 million in cash collateral for such contracts. In addition, the Company had posted $125$20.3 million in cash collateral forrelated to interest rate derivative contracts.

The Company also has a legal obligation associated with the decommissioning and dismantling of Summer Station Unit 1 and other conditional asset retirement obligations that are not listed in the contractual cash obligations table. See Notes 1 and 10 to the consolidated financial statements.

Financing Limits and Related Matters


The Company’s issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by regulatory bodies including state public service commissions and FERC. Financing programs currently utilized by the Company follow.

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Table of Contents

SCE&G and GENCO havehas obtained FERC authority to issue short-term indebtedness (pursuantand to assume liabilities as a guarantor(pursuant to Section 204 of the Federal Power Act). SCE&G may issue up to $1.2 billion of unsecured promissory notes, or commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, bankers, and dealers in commercial paper in amounts not to exceed $600 million.


35



GENCO mayhas obtained FERC authority to issue upshort-term indebtedness not to exceed $150 million outstanding with maturity dates of short-term indebtedness.one year or less. The authority to make such issuancesdescribed herein will expire in October 2012.

2014.


 In October 2013, the Company's existing committed LOCs were extended by one year. As a result, at December 31, 2013 SCANA, SCE&G (including Fuel Company) and PSNC Energy arewere parties to five-year credit agreements in the amounts of $300 million, $1.1$1.2 billion, of which $400$500 million relates to Fuel Company, and $100 million, respectively, which expire in October  23, 2015.2018. In addition, at December 31, 2013 SCE&G was 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’scompany'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 linesFor a list of banks providing credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A.support and Morgan Stanley Bank, N.A. each provide 10% ofother information, see Note 4 to the aggregate $1.5 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%.  Three other banks provide the remaining 6%. These bank credit facilities support the issuance of commercial paper by SCANA, SCE&G (including Fuel Company) and PSNC Energy. When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCANA, SCE&G (including Fuel Company) and PSNC Energy.

At December 31, 2011 and 2010, 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

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Lines of Credit:

 

 

 

 

 

 

 

 

 

 

 

 

 

Committed long-term

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

300

 

$

300

 

$

1,100

 

$

1,100

 

$

100

 

$

100

 

LOC advances

 

 

 

 

 

 

 

Weighted average interest rate

 

 

 

 

 

 

 

Outstanding commercial paper (270 or fewer days)

 

$

131

 

$

39

 

$

512

 

$

381

 

$

10

 

$

 

Weighted average interest rate

 

.63

%

.35

%

.56

%

.42

%

.57

%

 

Letters of credit supported by LOC

 

$

3

 

$

3

 

$

.3

 

$

.3

 

 

$

 

Available

 

$

166

 

$

258

 

$

588

 

$

719

 

$

90

 

$

100

 

consolidated financial statements.


As of December 31, 2011,2013, the Company had no outstanding borrowings under its $1.5$1.8 billion credit facilities, had approximately $653$376 million in commercial paper borrowings outstanding, was obligated under $3.3 million in LOC supported letters of credit, and held approximately $29$136 million in cash and temporary investments. The Company regularly monitors the commercial paper and short-term credit markets to optimize the timing for repayment of the outstanding balance on its draws, while maintaining appropriate levels of liquidity. Average short-term borrowings outstanding during 20112013 were approximately $573$463 million. Short-term cash needs were met primarily through the issuance of commercial paper.

At December 31, 2011,2013, the Company had net available liquidity of approximately $873 million. The Company regularly monitors the commercial paper and short-term credit markets to optimize the timing of replacement of any outstanding balance on its draws from the credit facilities, while maintaining appropriate levels of liquidity.  The Company’s long-term debt portfolio has a weighted average maturity of almost 17approximately 18 years and bears an average cost of 6.14%5.74%. A significant portionSubstantially all of the Company's 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.


The Company’s articles of incorporation do not limit the dividends that may be paid on its common stock. However, SCANA’s junior subordinated indenture (relating to the hereinafter defined Hybrids), SCE&G’s bond indenture (relating to the hereinafter defined Bonds) and PSNC Energy’s note purchase and debenture purchase agreements each contain provisions that, under certain circumstances which the Company considers to be remote, could limit the payment of cash dividends on their respective common stock.

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Table of Contents

With respect to hydroelectric projects, theThe Federal Power Act requires the appropriation of a portion of certain earnings therefrom.from hydroelectric projects.  At December 31, 2011,2013, approximately $58.8$63.1 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.

SCANA Corporation

SCANA has in effect an indenture which permits the issuance of unsecured debt securities from time to time including its medium-term notes. This indenture contains no specific limit on the amount of unsecured debt securities which may be issued.

SCANA has outstanding $150 million of enhanced junior subordinated notes (Hybrids) bearing anwhich bear interest rate ofat 7.70% and maturingmature on January 30, 2065, subject to extension to January 30, 2080. Because their structure and terms are characteristic of both debt instruments and equity securities, thecredit rating agencies consider securities like the Hybrids to be hybrid debt instruments and give some “equity credit”equity credit to the issuers of such securities for purposes of computing leverage ratios of debt to capital. The Hybrids are only subject to redemption at SCANA’s option and may be redeemed at any time, although the redemption prices payable by SCANA differ depending on the timing of the redemption and the circumstances (if any) giving rise thereto.

SCANA may redeem the Hybrids on or after January 30, 2015, without payment of a make-whole amount.

In connection with the Hybrids, SCANA executed an RCC in favor of the holders of certain designated debt (referred to as “covered debt”). Under the terms of the RCC, SCANA agreed not to redeem or repurchase all or part of the Hybrids prior to the termination date of the RCC, unless it uses the proceeds of certain qualifying securities sold to non-affiliates within 180 days prior to the redemption or repurchase date. The proceeds SCANA receives from such qualifying securities, adjusted by a predetermined factor, must exceed the redemption or repurchase price of the Hybrids. Qualifying securities include common stock, and other securities that generally rank equal to or junior to the Hybrids and include distribution, deferral and long-dated maturity features similar to the Hybrids. For purposes of the RCC, non-affiliates include (but are not limited to) individuals enrolled in SCANA’s dividend reinvestment plan, direct stock purchase plan and employee benefit plans.

The RCC is scheduled to terminate on the earliest to occur of the following: (a) January 30, 2035 (or later, if the maturity date of the Hybrids is extended), (b) the date on which SCANA no longer has any eligible debt which ranks senior in right of payment to the Hybrids, (c) the date on which the holders of at least a majority in principal amount of “covered debt”

36



agree to the termination thereof or (d) the date on which the Hybrids are accelerated following an event of default with respect thereto. SCANA’s $250 million in Medium Term Notes due April 1, 2020 were initiallyare designated as “covered debt” under the RCC.

South Carolina Electric & Gas Company

SCE&G is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its first mortgage bonds (Bonds) have been issued. Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, other than certain Bonds issued on the basis of retired Bonds, may be issued under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice (2.0) the annual interest requirements on all outstanding Bonds and Bonds to be outstanding (Bond Ratio). For the year ended December 31, 2011,2013, the Bond Ratio was 5.37.

5.28.

Financing Activities


During 2013 there were net cash outflows related to financing activities of approximately $40 million primarily due to repayment of short- and long-term debt and payment of dividends, partially offset by the issuance of common stock and long-term debt.
In June 2013, SCE&G issued $400 million of 4.60% first mortgage bonds due June 15, 2043. Proceeds from this sale were used to pay at maturity $150 million of its 7.125% first mortgage bonds due June 15, 2013, to repay short-term debt primarily incurred as a result of SCE&G's construction program, to finance capital expenditures, and for general corporate purposes.

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

On March 5, 2013, SCANA settled all forward sales contracts related to 6.6 million shares of its common stock, resulting in net proceeds of approximately $196 million.

In January 2013, JEDA issued for the benefit of SCE&G $39.5 million of 4.0% tax-exempt industrial revenue bonds due February 1, 2028, and $14.7 million of 3.625% tax-exempt industrial revenue bonds due February 1, 2033. Proceeds from these sales were loaned by JEDA to SCE&G and, together with other available funds, were used to redeem prior to maturity $56.9 million of 5.2% industrial revenue bonds due November 1, 2027.
In November 2012, SCE&G repaid at maturity $4.4 million of 4.2% tax-exempt industrial revenue bonds, and repaid prior to maturity $29.2 million of 5.45% tax-exempt industrial revenue bonds due November 1, 2032.

In July 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042 (issued at a premium with a yield of 3.86%), which constituted a reopening of the prior offering of $250 million of 4.35% first mortgage bonds which were issued in January 2012.  Proceeds from these sales were used to repay short-term debt primarily incurred as a result of SCE&G's construction program, to finance capital expenditures and for general corporate purposes.

In January 2012, SCANA issued $250 million of 4.125% medium term notes due February 1, 2022.  Proceeds from the sale were used by SCANA to retire $250 million of its 6.25% medium term notes due February 1, 2012. The borrowings refinanced by this 2012 issuance are classified within Long-term Debt, Net in the consolidated balance sheet.

In January 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042.  Proceeds from the sale were used to repay short-term debt primarily incurred as a result of our construction program, to finance capital expenditures and for general corporate purposes.

In October 2011, SCE&G issued $30 million of 3.22% first mortgage bonds due October 18, 2021.  Proceeds from the sale of these bonds were used to redeem prior to maturity $30 million of the 5.7% pollution control facilities revenue bonds due November 1, 2024 issued by Orangeburg County, South Carolina, on SCE&G’s behalf.

41


Investing Activities

Table of Contents

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

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

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

SCANA issued common stock valued at $59.2 million (at time of issue) in a public offering on May 17, 2010 and entered into forward agreements for the sale of approximately 6.6 million shares.  The forward agreements, after being extended by amendment dated October 26, 2011, are to be settled no later than December 31, 2012.

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

During 2011 the Company experienced net cash inflows related to financing activities of approximately $240 million primarily due to issuances of common stock and short-term and long-term debt, partially offset by repayment of long-term debt and payment of dividends.

The Company paid approximately $61$6 million, in 2011net, through the third quarter of 2013 to settle interest rate derivative contracts associated withupon the issuance of long-term debt for contracts that had been designated as hedges.


In addition, during the fourth quarter of 2013, the Company received approximately $120 million upon the settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt.

Pursuant to SCPSC accounting orders, $50.1 million of such gains were recognized within other income, with such gain recognition being fully offset by downward adjustments to revenues reflected within electric margin.

For additional information, on significant financing activities, see Note 4 to the consolidated financial statements.


37



In February 2012,2014, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.495$.525 per share, an increase of 2.1%approximately 3.5% from the prior declared dividend. The next quarterly dividend is payable April 1, 20122014 to shareholders of record on March 9,10, 2014.

In December 2010, the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 (Tax Relief Act) was signed into law.  Major tax incentives in the Tax Relief Act included 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 and 50% bonus depreciation for property placed in service for 2012.

  The American Taxpayer Relief Act of 2012 extended the 50% bonus depreciation for property placed in service in 2013.  These incentives, along with certain other deductions, have had a positive impact on the cash flows of the Company.


ENVIRONMENTAL MATTERS

The Company’s regulatedCompany'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. Compliance with these environmental requirements involves significant capital and operating costs, which the Company expects to recover through existing ratemaking provisions.

For the three years ended December 31, 2011,2013, the Company’sCompany's capital expenditures for environmental control equipment at its fossil fuel generating stations totaled $164.0$46.1 million. In addition, the Company made expenditures to operate and maintain environmental control equipment at its fossil plants of $9.2 million in 2013, $10.2 million in 2012 and $7.9 million during 2011, $6.5 million during 2010, and $5.6 million during 2009, which are included in “Other operation and maintenance” expense, and made expenditures to handle waste ash of $3.2 million in 2013, $7.9 million in 2012 and $8.7 million in 2011, $5.9 million in 2010, and $6.5 million in 2009, which are included in “Fuel used in electric generation.” In addition, included within “Other operation and maintenance” expense is an annual amortization of $1.4 million in each of 2011, 2010,2013, 2012 and 20092011 related to SCE&G’s&G's recovery of MGP remediation costs as approved by the SCPSC. It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for the Company are $35.0$9.5 million for 20122014 and $126.1$82.5 million for the four-year period 2013-2016.2015-2018.  These expenditures are included in the Company’sCompany's Estimated Capital Expenditures table, are discussed in Liquidity and Capital Resources, and include known costs related to the matters discussed below.

At the state level, no significant environmental legislation that would affect the Company’sCompany's operations advanced during 2011.2013. The Company cannot predict whether such legislation will be introduced or enacted in 2012,2014, or if new regulations or changes to existing regulations at the state level will be implemented in the coming year.  Several regulatory initiatives at the federal level did advance in 20112013 and more are expected to advance in 20122014 as described below.

42




Table of Contents

Air Quality

With the pervasive emergence of concern over the issue of global climate change as a significant influence upon the economy, SCANA, SCE&G and GENCO are subject to climate-related financial risks, including those involving regulatory requirements responsive to GHG emissions, as well as those involving other potential physical impacts which could arise from global climate change.impacts. Other business and financial risks arising from such climate change could also arise.materialize. The Company cannot predict all of the climate-related regulatory and physical risks nor the related consequences which might impact the Company, and the following discussion should not be considered all-inclusive.

As part of the President's Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA was directed to issue a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The rule became final on January 8, 2014 and requires all new fossil fuel-fired power plants to meet the carbon dioxide emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without carbon capture and sequestration capabilities. The Company is evaluating the final rule, but does not plan to construct new coal-fired units in the near future. The Memorandum also directed the EPA to issue standards, regulations, or guidelines for existing units by June 1, 2014, to be made final no later than June 1, 2015. The Company also cannot predict when rules will become final for existing units, if at all, or what conditions they may impose on the Company, if any. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

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,

38



SCE&G is engaged in pre-constructionconstruction 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 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels.  CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide.  SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements.  On July 6, 2011 the EPA issued the CSAPR.  This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. On August 21, 2012, the Court of Appeals vacated CSAPR and left CAIR in place. The EPA's petition for rehearing of the Court of Appeals' order was denied. In June 2013 the U.S. Supreme Court agreed to review the Court of Appeals' decision and oral arguments were held on December 10, 2013. A decision is still pending. Air quality control installations that SCE&G and GENCO have already completed should assisthave allowed the Company in complyingto comply with the reinstated CAIR and will also allow it to comply with CSAPR, and the reinstated CAIR.if reinstated. The Company will continue to pursue strategies to comply with all applicable environmental regulations.  Any costs incurred to comply with such regulations are expected to be recoverable through rates.

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


The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the NSPS of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In June 2010,addition, the DOJ, on behalf of the EPA, issued a final rulehas taken civil enforcement action against several utilities. The primary basis for a one-hour ambient air quality standard for sulfur dioxide.  This new standard may require some of SCE&G’s smaller coal-fired units to reduce their sulfur dioxide emissions to a level to be determinedthese actions is the assertion by the EPA and/or DHEC.  Thethat maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement. Though the Company cannot predict what action, if any, the EPA will initiate against it, any costs incurred to comply with this new standard are expected to be recoveredrecoverable through rates.


Physical effects associated with climate changes could include the impact of possible changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to the Company’sCompany's electric system, as well as impacts on employees and customers and on the Company’sCompany's supply chain and many others. Much of the service territory of SCE&G is subject to the damaging effects of Atlantic and Gulf coast hurricanes and also to the damaging impact of winter ice storms. To help mitigate the financial risks arising from these potential occurrences, SCE&G maintains insurance on certain properties andproperties. In addition, SCE&G has collected funds from customers for its storm damage reserve (see Note 2 to the consolidated financial statements). As part of its ongoing operations, SCE&G maintains emergency response and storm preparation plans and teams and applicable personnel participate inwho receive ongoing training and related simulations in advance of such storms, all in order to allow the Company to protect its assets and to return its systems to normal reliable operation in a timely fashion following any such event.

In December 2009, the EPA issued a final finding that atmospheric concentrations of GHG endanger public health and welfare within the meaning of Section 202(a) of the CAA. The rule, which became effective in January 2010, enables the EPA to regulate GHG emissions under the CAA. The EPA has committed to issue new rules regulating such emissions in 2012.  The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units.  In March 2011, the EPA proposed new standards for mercury and other specified air pollutants.  The rule, which becomes effective on April 16, 2012, provides up to four years for facilities to meet the standards.  The rule is currently being evaluated by the Company. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

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The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the new source performance standards of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement.

To date, SCE&G and GENCO have received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. The current state of continued DOJ civil enforcement is the subject of industry-wide speculation, and it cannot be determined whether the Company will be affected by the initiative in the future. The Company believes that any enforcement action relative to its compliance with the CAA would be without merit. The Company further believes that installation of equipment responsive to CAIR previously discussed will mitigate many of the alleged concerns with NSR.

Water Quality

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 nationalfacility’s NPDES permit program. Discharge permits have been issuedis 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 renewed for all of SCE&G’s and GENCO’s generating units. Concurrent with renewal of these permits, the permitting agency has implemented a more rigorous program of monitoring and controlling discharges, has modified the requirements for new cooling water intake structures, and has required strategies for toxicity reduction in wastewater streams.is expected to be finalized May 22, 2014. The EPA has said that it willexpects compliance as soon as possible after July 2017 but no later than July 2020.

Additionally, the EPA is expected to issue a rule by mid-2012 that modifies requirements for existing cooling water intake structures.structures in early 2014, The Company is conducting studies and is developing or implementing compliance plans for these initiatives. Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones and toxicity-based standards.zones. These provisions, if passed, could have a material impact on the financial condition, results of operations and cash flows of the Company, SCE&G and GENCO.Company. The Company believes that any additional costs imposed by such regulations would be recoverable through rates.


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Hazardous and Solid Wastes

The

In response to a federal court order to establish a definite timeline for a CCR rule, the EPA has stated its intention to propose, in late 2012,said it will issue new federal regulations affecting the management and disposal of CCRs, such as ash.ash, by December 2014. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO. While the Company cannot predict how extensive the regulations will be, the Company believes that any additional costs imposed by such regulations would be recoverable through rates.


The final CCR rule may require the closure of ash ponds.  SCE&G has three generating facilities that have employed ash storage ponds, and all of these ponds have either been closed after all ash was removed or are part of an ash pond closure project that includes complete removal of the ash prior to closure.  The electric generating facilities which continue to be coal-fired have dry ash handling, and the ash ponds undergoing closure have a detailed dam safety inspection conducted at least quarterly. 
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, 2011,2013, the federal government has not accepted any spent fuel from Summer Station Unit 1, or any other nuclear generating facility, 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 expects to be able to expand itshas commenced construction of a dry cask storage capacityfacility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1 through dry cask storage or1. 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. In addition, the states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in deferred debitsregulatory assets and amortized, with recovery provided through rates. The Company has assessed the following matters:

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Electric Operations

SCE&G has been named, along with 53 others, by the EPA as a PRP at the AER Superfund site located in Augusta, Georgia. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that was completed in 2010. A clean-up cost has been estimated and the PRPs have agreed to an allocation of those costs based primarily on volume and type of material each PRP sent to the site. SCE&G’s allocation did not have a material impact on its results of operations, cash flows or financial condition.

SCE&G maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. SCE&G defers site assessmentAmounts expected to be recovered through rates are recorded in regulatory assets and, cleanupif applicable, amortized over approved amortization periods. At December 31, 2013, such regulatory assets totaled approximately $1.2 million. Other environmental costs and expectsare recorded to recover them through rates.

expense as incurred.

Gas Distribution

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC.  SCE&G anticipates that major remediation activities at these sites will continue until 20142017 and will cost an additional $8.3$20.2 million.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates and insurance settlements.rates.  At December 31, 2011,2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.9$36.7 million and are included in regulatory assets.

PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy’sEnergy's actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. PSNC Energy has recorded a liability and associated regulatory asset of approximately $3.1$2.8 million, the estimated remaining liability at December 31, 2011.2013. PSNC Energy expects to recover through rates any cost net of insurance recovery, allocable to PSNC Energy arising from the remediation of these sites.


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REGULATORY MATTERS

SCANA and its subsidiaries are subject to the regulatory jurisdiction of the following entities for the matters noted.

CompanyRegulatory Jurisdiction/Matters
SCANAThe SEC as to the issuance of certain securities and other matters and the FERC as to certain acquisitions and other matters.
SCANA and all subsidiariesThe CFTC to the extent they transact swaps as defined in Dodd-Frank.
SCE&GThe SEC as to the issuance of certain securities and other matters; the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters; the FERC as to issuance of short-term borrowings, guarantees of short-term indebtedness, certain acquisitions and other matters; and the NRC with respect to the ownership, construction, operation and decommissioning of its currently operated and planned nuclear generating facilities. NRC jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety, antitrust considerations and environmental impact. In addition, the Federal Emergency Management Agency reviews, in conjunction with the NRC, certain aspects of emergency planning relating to the operation of nuclear plants.
SCE&G and GENCOThe FERC and DOE, under the Federal Power Act, as to the transmission of electric energy in interstate commerce, the sale of electric energy at wholesale for resale, the licensing of hydroelectric projects and certain other matters, including accounting.
GENCOThe SCPSC as to the issuance of securities (other than short-term borrowings) and the FERC as to issuance of short-term borrowings, accounting, certain acquisitions and other matters.
Fuel CompanyThe SEC as to the issuance of certain securities.
PSNC EnergyThe NCUC as to gas rates, service, issuance of securities (other than notes with a maturity of two years or less or renewals of notes with a maturity of six years or less), accounting and other matters, and the SEC as to the issuance of certain securities.
SCE&G, PSNC Energy and CGTThe PHMSA and the DOT as to integrity management requirements for gas distribution pipeline systems and natural gas transmission systems, respectively.
CGTThe FERC as to transportation rates, service, accounting and other matters.
SCANA EnergyThe GPSC through its certification as a natural gas marketer in Georgia and specifically as to retail prices for customers served under its regulated provider contract.

Material retail rate proceedings are described in more detail in Note 2 to the consolidated financial statements.

SCANA is subject to In addition, the jurisdiction of the SEC as to the issuance of certain securities and other matters and is subject to the jurisdiction of the FERC as to certain acquisitions and other matters.

South Carolina Electric & Gas Company

SCE&G is subject to the jurisdiction of the SEC as to the issuance of certain securities and other matters; the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters; and FERC as to issuance of short-term borrowings, certain acquisitions and other matters.

GENCO is subject to the jurisdiction of the SCPSC as to issuance of securities (other than short-term borrowings) and is subject to the jurisdiction of FERC as to issuance of short-term borrowings, accounting, certain acquisitions and other matters.

SCE&G and GENCO are subject to regulation under the Federal Power Act, administered by FERC and DOE, in the transmission of electric energy in interstate commerce and in the sale of electric energy at wholesale for resale, as well as with respect to licensed hydroelectric projects and certain other matters, including accounting.

NaturalRSA allows natural gas distribution companies mayin South Carolina to request annual adjustments to rates to reflect changes in revenues and expenses and changes in investment. Such annual adjustments are subject to certain qualifying criteria and review by the SCPSC.

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Effective February 12, 2010, the PHMSA issued a final rule establishing integrity management requirements for gas distribution pipeline systems. SCE&G has developed a plan and procedures to ensure that it will be fully compliant with this rule. SCE&G believes that any additional costs incurred to comply with the rule will be recoverable through rates.

Public Service Company of North Carolina, Incorporated

PSNC Energy is subject to the jurisdiction of the NCUC as to gas rates, issuance of securities (other than notes with a maturity of two years or less or renewals of notes with a maturity of six years or less), accounting and other matters.

The Pipeline Safety Act directed the DOT to establish the Integrity Management Rule for operations of natural gas systems with transmission pipelines located near moderate to high density populations. Of PSNC Energy’s approximately 617 miles of transmission pipeline subject to the Pipeline Safety Act, approximately 63 miles are located within these areas. Through December 2011, PSNC Energy has assessed 99 percent of the pipeline and is required to complete its assessment of the remainder by December 2012. PSNC Energy will be required to reinspect these same miles of pipeline approximately every seven years. PSNC Energy currently estimates the total costs through December 2012 to be $7.5 million for the initial assessments, not including any subsequent remediation that may be required. Costs totaling $2.2 million were recovered through rates over a three-year period beginning November 1, 2008. The NCUC has authorized continuation of deferral accounting for certain costs incurred to comply with DOT’s pipeline integrity management requirements until resolution of PSNC Energy’s next general rate proceeding.  As a result, PSNC Energy incurred an additional $3.5 million in costs between November 2008 and December 2011.

Carolina Gas Transmission Corporation

CGT has approximately 72 miles of transmission line that are covered by the Integrity Management Rule of the Pipeline Safety Act. CGT currently estimates the total cost to be $10.5 million for the initial assessments and any subsequent remediation required through December 2012.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Following are descriptions of the Company’s accounting policies and estimates which are most critical in terms of reporting financial condition or results of operations.

Utility Regulation

SCANA’s regulated utilities record certain assets and liabilities that defer the recognition of expenses and revenues to future periods in accordance with accounting guidance for rate-regulated utilities. In the future, in the event of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria of accounting for rate-regulated utilities, and could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on the

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results of operations, liquidity or financial position of the Company’s and SCE&G’s Electric DistributionOperations and Gas Distribution segments in the period the write-off would be recorded. See Note 2 to the consolidated financial statements for a description of the Company’s regulatory assets and liabilities, including those associated with the Company’s environmental assessment program.

The Company’s generation assets would be exposed to considerable financial risks in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, the Company could be required to write down its investment in those assets. The Company cannot predict whether any write-downs would be necessary and, if they were, the extent to which they would affect the Company’s results of operations in the period in which they would be recorded. As of December 31, 2011,2013, the Company’s net investments in fossil/hydro and nuclear generation assets were approximately $3.1$2.4 billion and $1.8$2.9 billion, respectively.


Revenue Recognition and Unbilled Revenues

Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers of the Company’s utilities and retail gas operations are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, the Company records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to customers for which they have not yet been billed. Such unbilled revenues reflect consideration of estimated usage by customer class,

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the effects of different rate schedules changes in weather and, where applicable, the impact of weather normalization or other regulatory provisions of rate structures. The accrual of unbilled revenues in this manner properly matches revenues and related costs. Accounts receivable included unbilled revenues of $169.1$183.1 million at December 31, 20112013 and $221.1$189.8 million at December 31, 2010,2012, compared to total revenues of $4.4$4.5 billion and $4.6$4.2 billion for the years 20112013 and 2010,2012, respectively.

Nuclear Decommissioning

Accounting for decommissioning costs for nuclear power plants involves significant estimates related to costs to be incurred many years ininto the future. Among the factors that could change SCE&G’s accounting estimates related to decommissioning costs are changes in technology, changes in regulatory and environmental remediation requirements, and changes in financial assumptions such as discount rates and timing of cash flows. Changes in any of these estimates could significantly impact the Company’s financial position and cash flows (although changes in such estimates should be earnings-neutral, because these costs are expected to be collected from ratepayers).

Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, including both the cost of decommissioning plant components that are and are not subject to radioactive contamination, totals $451.0$696.8 million, stated in 20062012 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station Unit 1. The cost estimate assumes that upon closure the site would be maintained over a period offor 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use.

Under SCE&G’s method of funding decommissioning costs, amounts collected through rates are invested in insurance policies on the lives of certain Company personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.

Accounting for Pensions and Other Postretirement Benefits

The Company recognizes the overfunded or underfunded status of its defined benefit pension plan as an asset or liability in its balance sheet and changes in funded status as a component of net periodic benefit cost or other comprehensive income, net of tax, or as a regulatory asset as required by accounting guidance. The Company’s plan is adequately funded under current regulations. Accounting guidance requires the use of several assumptions, the selection of which may have a large impact on the resulting pension cost or income recorded. Among the more sensitive assumptions are those surrounding discount rates and expected returns on assets. Net pension cost of $17.3 million recorded in 2011 reflects the use of a 5.56% discount rate, derived using a cash flow matching technique, and an assumed 8.25% long-term rate of return on plan assets. The Company believes that these assumptions were, and that the resulting pension cost amount was, reasonable. For purposes of comparison, using a discount rate of 5.31% in 2011 would have increased the Company’s pension cost by $1.3 million. Had the assumed long-term rate of return on assets been 8.00%, the Company’s pension cost for 2011 would have increased by $1.9 million.

The following information with respect to pension assets (and returns thereon) should also be noted.

The Company determines the fair value of a majority of its pension assets utilizing market quotes or derives them from modeling techniques that incorporate market data. Only a small portion of assets are valued using less transparent (so-called “Level 3”) methods.

In developing the expected long-term rate of return assumptions, the Company evaluates historical performance, targeted allocation amounts and expected payment terms. As of the beginning of 2011, the plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 4.2%, 8.1%, 9.8% and 10.2%, respectively. The 2011 expected long-term rate of return of 8.25% was based on a target asset allocation of 65% with equity managers and 35% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. As of the beginning of 2012, the plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 4.2%, 6.8%, 8.6% and 9.3%, respectively. For 2012, the expected rate of return is 8.25%.

Due to turmoil in the financial markets and the resultant declines in plan asset values in the fourth quarter of 2008, the Company recorded significant amounts of pension cost in 2009, 2010 and 2011 compared to the pension income recorded previously. However, in February 2009, SCE&G was granted accounting orders by the SCPSC which allowed it to mitigate a significant portion of this pension cost by deferring as a regulatory asset the amount of pension expense above the level that was included in then current cost of service rates for its retail electric and gas distribution regulated operations. In July 2010,

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upon the new retail electric base rates becoming effective, SCE&G began deferring as a regulatory asset all pension cost related to its regulated retail electric operations that otherwise would have been charged to expense. In November 2010, upon the updated gas rates becoming effective under the RSA, SCE&G began deferring as a regulatory asset all pension cost related to its regulated natural gas operations that otherwise would have been charged to expense.

The pension trust is adequately funded under current regulations, and no contributions have been required since 1997. Management does not anticipate the need to make significant pension contributions until after 2012.

The Company accounts for the cost of its postretirement medical and life insurance benefit plans in a similar manner to that used for its defined benefit pension plan. This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. The Company used a discount rate of 5.72%, derived using a cash flow matching technique, and recorded a net cost of $18.6 million for 2011. Had the selected discount rate been 5.47% (25 basis points lower than the discount rate referenced above), the expense for 2011 would have been $0.5 million higher. Because the plan provisions include “caps” on company per capita costs, healthcare cost inflation rate assumptions do not materially impact the net expense recorded.

Asset Retirement Obligations

The Company accrues for the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation in accordance with applicable accounting guidance. The obligations are recognized at fairpresent value in the period in which they are incurred, and associated asset retirement costs are capitalized as a part of the carrying amount of the related long-lived assets. Because such obligations relate primarily to the Company’s regulated utility operations, their recordingrecognition has no significant impact on results of operations. As of December 31, 2011,2013, the Company has recorded an AROAROs of $124$191 million for nuclear plant decommissioning (as discussed above) and an AROAROs of $349$385 million for other conditional obligations primarily related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded in accordance with the relevant accounting guidance are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments may be made many years in the future. Changes in these estimates will be recorded over time; however, these changes in estimates are not expected to materially impact results of operations so long as the regulatory framework for the utilities remains in place.

OTHER MATTERS

Nuclear Generation


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Accounting for Pensions and Other Postretirement Benefits
The Company recognizes the funded status of its defined benefit pension plan as an asset or liability and changes in funded status as a component of net periodic benefit cost or other comprehensive income, net of tax, or as a regulatory asset as required by accounting guidance. The Company’s plan is adequately funded under current regulations. Accounting guidance requires the use of several assumptions, the selection of which has an impact on the resulting pension cost recorded. Among the more sensitive assumptions are those surrounding discount rates and expected returns on assets. Net pension cost of $31.7 million recorded in 2013 reflects the use of a 4.10% discount rate prior to re-measurement on September 1, 2013 and a 5.07% discount rate after re-measurement, derived using a cash flow matching technique, and an assumed 8.0% long-term rate of return on plan assets. The re-measurement occurred in connection with a plan amendment and related curtailment, which is further described below. The Company believes that these assumptions were, and that the resulting pension cost amount was, reasonable. For purposes of comparison, a 25 basis point reduction in the discount rate in 2013 would have increased the Company’s pension cost by $1.2 million. Further, had the assumed long-term rate of return on assets been 7.75%, the Company’s pension cost for 2013 would have increased by $1.9 million.
The following information with respect to pension assets (and returns thereon) should also be noted.
The Company determines the fair value of a large majority of its pension assets utilizing market quotes or derives them from modeling techniques that incorporate market data. Less than 10% of assets are valued using less transparent Level 3 methods.
In developing the expected long-term rate of return assumptions, the Company evaluates historical performance, targeted allocation amounts and expected payment terms. As of the beginning of 2013, the plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 7.5%, 6.3%, 8.8% and 9.7%, respectively. The 2013 expected long-term rate of return of 8.00% was based on a target asset allocation of 58% with equity managers, 33% with fixed income managers and 9% with hedge fund managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. As of the beginning of 2014, the plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 6.4%, 6.0%, 8.3% and 9.3%, respectively. For 2014, the expected rate of return is 8.00%.
As of December 31, 2013, 2012, and 2011, approximately $5.5 million, $14.9 million and $9.0 million, respectively, of pension expense was deferred pursuant to regulatory orders. As part of a December 2012 SCPSC rate order, cumulative previously deferred pension costs related to electric operations of approximately $63 million is being amortized over approximately 30 years, and starting in January 2013 current pension expense for electric operations is being recovered through a pension cost rider. Similarly, in connection with the October 2013 RSA order, previously deferred pension cost related to gas operations of approximately $14 million is being amortized over approximately 14 years, and effective November 2013, SCE&G is recovering current pension expense related to gas operations through cost of service rates.

In the third quarter of 2013, the pension plan was amended such that pension benefits will no longer be offered to employees hired or rehired after December 31, 2013, and Santee Cooperpension benefits for existing participants will no longer accrue for services performed or compensation earned after December 31, 2023. As a result, the Company recorded a curtailment charge due to the accelerated amortization of prior service cost. Approximately $6.5 million of the curtailment charge was applicable to regulated operations and was deferred within regulatory assets. The Company is recovering such deferred amounts through existing regulatory orders.

The closure of the plan to entrants after December 31, 2013 and the cessation of benefit accruals in 2023 are partiesexpected to construction and operating agreements in which they agreed to be joint owners, and share operatingfurther lessen the significance of pension costs and generation output,the criticality of the related estimates to the Company's financial statements. Further, the pension trust is adequately funded under current regulations, and management does not anticipate the need to make significant pension contributions for the foreseeable future.
The Company accounts for the cost of its postretirement medical and life insurance benefit plans in a similar manner to that used for its defined benefit pension plan. This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. The Company used a discount rate of 4.19%, derived using a cash flow matching technique, and recorded a net cost of $21.3 million for 2013. Had the selected discount rate been 3.94% (25 basis points lower than the discount rate referenced above), the expense for 2013 would have been $0.6 million higher. Because the plan provisions include “caps” on company per capita costs, and because employees hired after December 31, 2010 are responsible for the full cost of retiree medical benefits elected by them, healthcare cost inflation rate assumptions do not materially impact the net expense recorded. 

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NEW NUCLEAR CONSTRUCTION MATTERS

SCE&G is constructing two 1,117-MW1,250 MW (1,117 MW, net) nuclear generation units to be constructed at the site of Summer Station,Station. SCE&G will jointly own the New Units with Santee Cooper, and SCE&G will be responsible for 55 percent of the cost of and receiving 55 percent ofreceive the output andfrom the New Units in proportion to its share of ownership, with Santee Cooper responsible for and receiving the remaining 45 percent.share. SCE&G's current ownership share in the New Units is 55%. Under these agreements,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. Under the terms of this agreement, SCE&G will have the primary responsibility for oversight of the construction ofacquire a one percent ownership interest in the New Units at the commercial operation date of Unit 2, will acquire an additional two percent ownership interest no later than the first anniversary of such commercial operation date, and will be responsible foracquire the final two percent no later than the second anniversary of such commercial operation date. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units as they come online.

SCE&G, on behalf of itself and as agent for Santee Cooper, has entered into the EPC Contract with the Consortium for the design and construction ofto third parties until the New Units.Units are complete.


It is expected that Unit 2 will be placed in service in the fourth quarter of 2017 or the first quarter of 2018, with Unit 3's in-service date approximately 12 months later. SCE&G’s&G's share of the estimated cash outlays (future value, excluding AFC) for its current 55% ownership share totals approximately $6$5.4 billion for plant costs and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC.

As In addition, under the terms of the agreement previously reported,described, SCE&G has been advised byagreed to pay an amount equal to Santee Cooper that it is reviewing certain aspectsCooper's actual cost of its capital improvement program and long-term power supply plan, including the levelpercentage conveyed as of its participation inthe date of conveyance, which SCE&G estimates will be approximately $500 million for the entire 5% interest. This transaction will not affect the payment obligations between the parties during construction for the New Units.  Santee Cooper has entered into a letterUnits, nor is it anticipated that the payments would be reflected in revised rates filings under the BLRA.


In November 2012, the SCPSC approved an updated construction schedule and additional updated capital costs of intent with Duke that may result$278 million (SCE&G's portion in Duke acquiring a2007 dollars). The November 2012 order approved additional identifiable capital costs of approximately $1 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications; approximately $8 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure; and approximately $132 million (SCE&G's portion in 2007 dollars) related to additional labor for the oversight of Santee Cooper’s ownership interest in the New Units.Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. In addition, the order approved revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims for costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict whether any changethe outcome of these appeals.

The Consortium has experienced delays in Santee Cooper’s ownership interest or the additionschedule for fabrication and delivery of new joint owners will increase project costs or delay the commercial operation dates ofsub-modules for the New Units. Any such project cost increase or delay could be material.

The Consortium has recently performed an impact study, at SCE&G’s request, related to various costfabrication and timing alternatives arising from the delay in the issuance datedelivery of sub-modules are a focus area of the COL from mid-2011,Consortium, including sub-modules for module CA20, which wasis part of the date assumed whenauxiliary building, and CA01, which houses components inside the EPC Contract was signed in 2008,containment vessel. Modules CA20 and CA01 are considered critical path items for both New Units. All sub-modules for CA20 have been received on site and its fabrication is underway. CA20 is expected to be ready for placement on the early-2012 issuance date currently anticipated by SCE&G. The impact study analyzed three scenarios, including (1) compressing the construction schedule for the first New Unit but retaining the original substantial completion dates set forth in the EPC Contract, (2) extending the substantial completion date for the first New Unit to accommodate the COL delay, or (3) delaying the substantial completion datenuclear island of the first New Unit and acceleratingin the

48



Table first quarter of Contents

2014. In addition, the delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow it to be ready for placement on the nuclear island of the first New Unit during the third quarter of 2014. With this schedule, the Consortium continues to indicate that the substantial completion date forof the first New Unit is expected to be late 2017 or the first quarter of 2018 and that the substantial completion of the second New Unit is expected to be approximately twelve months after that of the first New Unit. The substantial completion dates currently approved by the SCPSC for the first and second New Units are March 15, 2017 and May 15, 2018, respectively. The SCPSC has also approved an 18-month contingency period beyond each of these dates. The preliminary expected new substantial completion dates are within the contingency periods. SCE&G cannot predict with certainty the extent to which the issue with the sub-modules or the delays in the substantial completion of the New Units will result in increased project costs. However, the preliminary estimate of the delay-related costs associated with SCE&G's 55% share of the New Units is approximately $200 million. SCE&G has recently informednot accepted responsibility for any of these delay-related costs and expects to have further discussions with the Consortium that it intendsregarding such responsibility. Additionally, the EPC Contract provides for liquidated damages in the event of a delay in the completion of the New Units, which will also be included in discussions with the Consortium. SCE&G believes its responsibility for any portion of the $200 million estimate should ultimately be substantially less, once all of the relevant factors are considered.


In addition to pursue scenario (3)the above-described project delays, SCE&G is also aware of financial difficulties at a supplier responsible for certain significant components of the project.  The Consortium is monitoring the potential for disruptions in

44



such equipment fabrication and has also begun discussions concerningpossible responses.   Any disruptions could impact the update of cash flow forecastsproject's schedule or costs, and construction schedules on that basis.

such impacts could be material.


The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude.  During the course of activities under the EPC Contract, issues have materialized that may impact project budget and schedule, including those relatedschedule. Claims specifically relating to COL delays,
design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock
conditions at the site.  These issues havesite resulted in assertions of contractual entitlement to recover additional costs and may resultto be incurred. The resolution
of these specific claims is discussed in requests for change orders fromNote 2 to the Consortium.  While SCE&G has not accepted the validity of any claims, the total amount of the claims presented (SCE&G’s portion in 2007 dollars) is approximately $188 million.consolidated financial statements. SCE&G expects to resolve any such disputes that arise in the future, including any which may arise with respect to the delay-related costs discussed above, through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time, (see Note 2 to the consolidated financial statements), will be recoverable through rates.

On February 29, 2012, SCE&G filed


During the fourth quarter of 2013, the Consortium began a petition withfull re-baselining of the SCPSC seeking an order approvingUnit 2 and Unit 3 construction schedules to incorporate a further updated capital costmore detailed evaluation of the engineering and procurement activities necessary to accomplish the schedule 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 schedules, construction work crew assignments, and other items. The result will be a revised fully integrated construction schedule that incorporates additional identifiable capital costswill provide for detailed and itemized information on individual budget and cost categories, cost estimates at completion for all non-firm and fixed scopes of approximately $6 million (SCE&G’s portionwork, and the timing of specific construction activities and cash flow requirements. SCE&G anticipates that this revised schedule and the cost estimate at completion for all non-firm and fixed scopes of work will be finalized in 2007 dollars) relatedthe third quarter of 2014. SCE&G plans to reevaluate and reschedule its owners cost estimates and cash flow requirements in light of the new federal healthcare laws, information security measures and certain minor design modifications.  That petition also includes increased capital costs of approximately $12 million (SCE&G’s portion in 2007 dollars) related to transmission infrastructure.  Finally, that petition includes amounts of approximately $137 million (SCE&G’s portion in 2007 dollars) related to additional laborschedule.

When the NRC issued the COLs for the oversightNew Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units during constructionUnits' passive cooling system, and for preparingrequiring the development of strategies to operaterespond to extreme natural events resulting in the loss of power at the New Units, facilitiesUnits.  In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation, as well as a request for information related to emergency plant staffing.  These conditions and information technology systems requiredrequirements are responsive to support the New Units and their personnel.  Future petitions would be filedNRC's Near-Term Task Force report titled “Recommendations for any costs arising fromEnhancing Reactor Safety in the resolution21st Century.”  This report was prepared in the wake of the commercial claims discussed above.

Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. In September 2011, the SCPSC approved an increase of $52.8 million or 2.4% under the BLRA for the annual revised rates adjustment filing. The new retail electric rates were effective for bills rendered on and after October 30, 2011.

In March 2011 aearthquake-generated tsunami, resulting from a massive earthquakewhich severely damaged several nuclear generating units and their back-up cooling systems in Japan.  TheSCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the disaster is being evaluated world-wide,construction and numerous politicaloperation of the New Units, and regulatory bodies, including those in the United States, are seeking to determine if additional safety measures should be required at existing nuclear facilities, as well as those planned for construction.  In particular, on July 12, 2011, the NRC’s Near-Term Task Force issued a report titled “Recommendations for Enhancing Reactor Safety in the 21st Century,” which SCE&G, is evaluating.pursuant to the license condition, prepared and submitted an integrated response plan for the New Units to the NRC in August 2013.  SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, noror how such initiatives would impact SCE&G’s&G's existing Summer Station or the licensing, construction or operation of the New Units.

In December 2011,


Subject to a national megawatt capacity limitation, the NRC granted final design certification to Westinghouse for the AP1000 nuclear reactor, which is the reactorelectricity to be used for the New Units.  This certification is a necessary step before the NRC can issue a COL for the New Units.  In October 2011, the NRC conducted a mandatory hearing regarding the issuance of a COL for the New Units.  This hearing followed the August 2011 completion of the FSER, in which the NRC staff concluded there were no safety aspects that would preclude issuing the COL, and the April 2011 completion of the FEIS, in which the NRC and the USACE concluded there were no environmental impacts that would preclude issuing the COL.

Fuel Contract

On January 27, 2011, SCE&G, for itself and as agent for Santee Cooper, and Westinghouse entered into a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, Westinghouse will supply enriched nuclear fuel assemblies for Summer Station Unit 1 and the New Units. Westinghouse will be SCE&G’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements of Summer Station Unit 1 andproduced by the New Units through 2033.(advanced nuclear units, as defined) is expected to qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code. Following the pouring of safety-related concrete for each of the New Units’ reactor buildings (March 2013 for the first New Unit and November 2013 for the second New Unit), SCE&G is dependent upon Westinghousehas applied to the IRS for providing fuel assembliesits allocations of such national megawatt capacity limitation. The IRS will forward the applications to the DOE for appropriate certification. Under current provisions of the new AP1000 passive reactorsInternal Revenue Code and based on SCE&G's current 55% ownership and other assumptions regarding volumes of electricity to be generated by the New Units, the aggregate production tax credits for which SCE&G qualifies could exceed $1.3 billion over the eight year period following each of the New Units' in-service dates. In January 2014, SCE&G amended its application to include the additional 5% interest in the New Units in the current and anticipated future absence of other commercially viable sources. Westinghouse currently provides maintenance and engineering supportthat it expects to Summer Station Unit 1 under a services alliance arrangement, and SCE&G has also contracted for Westinghouse to provide similar support servicesacquire. Additional production tax credits related to the New Units upon their completion and commencement of commercial operation.

5% interest could total as much as $125 million.


OTHER MATTERS
Financial Regulatory Reform

In July 2010,

Dodd-Frank became law. This Act provides for substantial additional regulation of over-the-counter and security-based derivative instruments, among other things, and requires numerous rule-makings by the Commodity

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Table of Contents

Futures Trading CommissionCFTC and the SEC to implement. The Company has determined that it meets the end-user exception in Dodd-Frank, with the lowest level of required regulatory reporting burden imposed by this law. The Company is currently complying with these enacted regulations and intends to comply with regulations enacted in the future, but cannot predict when the final regulations will be issued or what requirements they will impose.



45



Off-Balance Sheet Transactions

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

Claims and Litigation

For a description of claims and litigation see Item 3. LEGAL PROCEEDINGS and Note 10 to the consolidated financial statements.

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Table of Contents

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

All financial instruments held by the Company described below are held for purposes other than trading.

Interest Rate Risk

The tables below provides information about long-term debt issued by the Company and other financial instruments that are sensitive to changes in interest rates. For debt obligations, the tables present principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the figures shown reflect notional amounts, weighted average interest rates and related maturities. Fair values for debt represent quoted market prices. Interest rate swap agreements are valued using discounted cash flow models with independently sourced data.

December 31, 2011

 

Expected Maturity Date

 

Millions of dollars

 

2012

 

2013

 

2014

 

2015

 

2016

 

Thereafter

 

Total

 

Fair Value

 

Long-Term Debt:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed Rate ($)

 

269.9

 

160.7

 

44.8

 

8.4

 

7.7

 

3,990.0

 

4,481.5

 

5,330.1

 

Average Fixed Interest Rate (%)

 

6.19

 

7.00

 

4.96

 

5.50

 

5.54

 

5.84

 

5.89

 

 

Variable Rate ($)

 

4.4

 

4.4

 

4.4

 

4.4

 

4.4

 

147.5

 

169.5

 

147.1

 

Average Variable Interest Rate (%)

 

1.23

 

1.23

 

1.23

 

1.23

 

1.23

 

0.74

 

0.80

 

 

Interest Rate Swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pay Variable/Receive Fixed ($)

 

253.2

 

 

 

 

 

 

253.2

 

0.3

 

Pay Interest Rate (%)

 

5.07

 

 

 

 

 

 

5.07

 

 

Receive Interest Rate (%)

 

6.28

 

 

 

 

 

 

6.28

 

 

Pay Fixed/Receive Variable ($)

 

504.4

 

154.4

 

4.4

 

4.4

 

4.4

 

150.6

 

822.6

 

(156.5

)

Average Pay Interest Rate (%)

 

3.41

 

4.92

 

6.17

 

6.17

 

6.17

 

4.80

 

3.99

 

 

Average Receive Interest Rate (%)

 

.59

 

.60

 

1.23

 

1.23

 

1.23

 

.70

 

.62

 

 

December 31, 2010

 

Expected Maturity Date

 

Millions of dollars

 

2011

 

2012

 

2013

 

2014

 

2015

 

Thereafter

 

Total

 

Fair Value

 

Long-Term Debt:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed Rate ($)

 

623.0

 

268.6

 

159.8

 

43.7

 

7.8

 

3,196.6

 

4,299.5

 

4,666.0

 

Average Fixed Interest Rate (%)

 

6.76

 

6.20

 

7.02

 

4.97

 

5.48

 

6.07

 

6.20

 

 

Variable Rate ($)

 

4.4

 

4.4

 

4.4

 

4.4

 

4.4

 

155.0

 

177.0

 

162.7

 

Average Variable Interest Rate (%)

 

1.00

 

1.00

 

1.00

 

1.00

 

1.00

 

.72

 

.76

 

 

Interest Rate Swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pay Variable/Receive Fixed ($)

 

303.2

 

253.2

 

 

 

 

 

556.4

 

4.0

 

Pay Interest Rate (%)

 

6.02

 

4.92

 

 

 

 

 

5.52

 

 

Receive Interest Rate (%)

 

6.89

 

6.28

 

 

 

 

 

6.62

 

 

Pay Fixed/Receive Variable ($)

 

654.4

 

254.4

 

4.4

 

4.4

 

4.4

 

155.0

 

1,077.0

 

(77.5

)

Average Pay Interest Rate (%)

 

4.59

 

4.21

 

6.17

 

6.17

 

6.17

 

4.84

 

4.56

 

 

Average Receive Interest Rate (%)

 

.31

 

.31

 

1.00

 

1.00

 

1.00

 

.68

 

.37

 

 

December 31, 2013 Expected Maturity Date
Millions of dollars 2014 2015 2016 2017 2018 Thereafter Total Fair Value
Long-Term Debt:  
  
  
  
  
  
  
  
Fixed Rate ($) 46.7
 10.8
 109.6
 8.7
 717.9
 4,386.5
 5,280.2
 5,753.3
Average Fixed Interest Rate (%) 4.83
 4.72
 1.14
 4.84
 5.95
 5.43
 5.40
 
Variable Rate ($) 4.4
 4.4
 4.4
 4.4
 4.4
 138.2
 160.2
 154.4
Average Variable Interest Rate (%) 0.94
 0.94
 0.94
 0.94
 0.94
 0.53
 0.59
 
Interest Rate Swaps:  
  
  
  
        
Pay Fixed/Receive Variable ($) 604.4
 654.4
 4.4
 4.4
 4.4
 141.8
 1,413.8
 13.0
Average Pay Interest Rate (%) 3.97
 4.17
 6.17
 6.17
 6.17
 4.72
 4.16
 
Average Receive Interest Rate (%) 0.25
 0.25
 0.94
 0.94
 0.94
 0.49
 0.28
 
December 31, 2012 Expected Maturity Date
Millions of dollars 2013 2014 2015 2016 2017 Thereafter Total Fair Value
Long-Term Debt:  
  
  
  
  
  
  
  
Fixed Rate ($) 162.0
 46.1
 9.8
 8.6
 7.7
 4,706.0
 4,940.2
 5,941.4
Average Fixed Interest Rate (%) 6.96
 4.86
 4.92
 5.03
 5.12
 5.59
 5.63
 
Variable Rate ($) 4.4
 4.4
 4.4
 4.4
 4.4
 142.6
 164.6
 157.5
Average Variable Interest Rate (%) 1.01
 1.01
 1.01
 1.01
 1.01
 0.61
 0.66
 
Interest Rate Swaps:  
  
  
  
        
Pay Fixed/Receive Variable ($) 604.4
 304.4
 4.4
 4.4
 4.4
 146.2
 1,068.2
 (33.6)
Average Pay Interest Rate (%) 3.04
 2.53
 6.17
 6.17
 6.17
 4.76
 3.17
 
Average Receive Interest Rate (%) 0.31
 0.32
 1.01
 1.01
 1.01
 0.58
 0.36
 
While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur.

The above tables exclude long-term debt of $15$3 million at December 31, 20112013 and $21$9 million at December 31, 2010,2012, which amounts do not have a stated interest rate associated with them.


46



For further discussion of the Company’s long-term debt and interest rate derivatives, see ITEMItem 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — LIQUIDITY AND CAPITAL RESOURCESLiquidity and alsoCapital Resources and Notes 4 and 6 ofto the condensed consolidated financial statements.

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Table of Contents

Commodity Price Risk

The following tables provide information about the Company’s financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 DT.MMBTU. Fair value represents quoted market prices.

Expected Maturity:

 

 

 

 

 

 

 

 

Options

 

Future Contracts

 

 

 

Purchased
Call

 

Purchased
Put

 

Sold
Call

 

Sold
Put

 

 

 

Long

 

Short

 

 

 

(Long)

 

(Short)

 

(Short)

 

(Long)

 

2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Settlement Price(a)

 

3.12

 

3.90

 

Strike Price(a)

 

4.63

 

3.75

 

5.00

 

3.75

 

Contract Amount(b)

 

17.0

 

0.2

 

Contract Amount(b)

 

38.7

 

0.2

 

0.2

 

0.2

 

Fair Value(b)

 

13.5

 

0.3

 

Fair Value(b)

 

0.4

 

 

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Settlement Price(a)

 

3.88

 

 

Strike Price(a)

 

4.60

 

 

 

 

Contract Amount(b)

 

1.4

 

 

Contract Amount(b)

 

3.5

 

 

 

 

Fair Value(b)

 

1.2

 

 

Fair Value(b)

 

0.2

 

 

 

 


Expected Maturity:          
Futures Contracts    Options     
       Purchased Call Purchased Put 
2014Long Short 2014 (Long) (Short) 
Settlement Price (a)4.18 4.17
 Strike Price (a) 4.01 4.10 
Contract Amount (b)13.0 0.7
 Contract Amount (b) 26.6 0.2 
Fair Value (b)14.0 0.7
 Fair Value (b) 2.2  
           
2015   
 2015     
Settlement Price (a)4.27 4.1
 Strike Price (a) 4.30  
Contract Amount (b)1.1 0.2
 Contract Amount (b) 0.1  
Fair Value (b)1.2 0.2
 Fair Value (b)   
(a)               Weighted average, in dollars

(b)              Millions of dollars

Swaps

 

2012

 

2013

 

2014

 

2015

 

2016

 

Commodity Swaps:

 

 

 

 

 

 

 

 

 

 

 

Pay fixed/receive variable(b)

 

86.2

 

24.4

 

11.7

 

11.6

 

5.1

 

Average pay rate(a)

 

4.2928

 

5.5068

 

5.3603

 

5.3764

 

5.3088

 

Average received rate(a)

 

3.1876

 

3.9337

 

4.3395

 

4.5970

 

4.8541

 

Fair Value(b)

 

64.0

 

17.4

 

9.5

 

9.9

 

4.7

 

Pay variable/receive fixed(b)

 

48.5

 

14.3

 

9.4

 

9.9

 

4.7

 

Average pay rate(a)

 

3.2090

 

3.9361

 

4.3395

 

4.5970

 

4.8541

 

Average received rate(a)

 

4.2887

 

5.3655

 

5.3867

 

5.3867

 

5.3163

 

Fair Value(b)

 

64.9

 

19.5

 

11.6

 

11.6

 

5.1

 

Basis Swaps:

 

 

 

 

 

 

 

 

 

 

 

Pay variable/receive variable(b)

 

26.2

 

5.9

 

 

 

 

Average pay rate(a)

 

3.2342

 

3.9336

 

 

 

 

Average received rate(a)

 

3.2102

 

3.8825

 

 

 

 

Fair Value(b)

 

26.1

 

5.9

 

 

 

 


Swaps 2014 2015 2016 2017 
Commodity Swaps:  
  
  
  
 
Pay fixed/receive variable (b) 51.9
 17.1
 10.0
 1.0
 
Average pay rate (a) 4.2063
 4.9039
 4.7098
 4.1275
 
Average received rate (a) 4.1774
 4.1634
 4.1284
 4.1530
 
Fair Value (b) 51.6
 14.5
 8.8
 1.1
 
Pay variable/receive fixed (b) 32.4
 14.0
 8.7
 1.1
 
Average pay rate (a) 4.1720
 4.1621
 4.1296
 4.1530
 
Average received rate (a) 4.2845
 4.9363
 4.7143
 4.1325
 
Fair Value (b) 33.3
 16.6
 9.9
 1.1
 
Basis Swaps:  
  
  
  
 
Pay variable/receive variable (b) 1.0
 0.5
 
 
 
Average pay rate (a) 4.2256
 4.3982
 
 
 
Average received rate (a) 4.1700
 4.3767
 
 
 
Fair Value (b) 1.0
 0.5
 
 
 
(a)               Weighted average, in dollars

(b)              Millions of dollars

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 6 to the consolidated financial statements. The information above includes those financial positions of Energy Marketing SCE&G and PSNC Energy.

SCE&G and

PSNC Energy utilizeutilizes futures, options and swaps to hedge gas purchasing activities. SCE&G’s tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCE&G’s hedging activities are to be included in the PGA. As such, costs of related derivatives utilized by SCE&G to hedge gas purchasing activities are recoverable through weighted average cost of gas calculations. The offset to the change in fair value of these derivatives is deferred. PSNC Energy’s tariffs also include a provision for the recovery of actual gas costs incurred. PSNC Energy defers premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program for subsequent recovery from customers.

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Table of Contents

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

SCANA Corporation

Cayce, South Carolina


We have audited the accompanying consolidated balance sheets of SCANA Corporation and subsidiaries (the “Company”"Company") as of December 31, 20112013 and 2010,2012, and the related consolidated statements of income, comprehensive income, cash flows, and changes in common equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2011.2013. Our audits also included the financial statement schedule listed in Part IV at Item 15. These financial statements and the financial statement schedule are the responsibility of the Company’sCompany's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.


We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.


In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20112013 and 2010,2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011,2013, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.


We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’sCompany's internal control over financial reporting as of December 31, 2011,2013, based on the criteria established in Internal Control—IntegratedControl-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 29, 2012,28, 2014 expressed an unqualified opinion on the Company’sCompany's internal control over financial reporting.


/s/DELOITTE & TOUCHE LLP

Charlotte, North Carolina

February 29, 2012

28, 2014

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SCANA Corporation

CONSOLIDATED BALANCE SHEETS

December 31, (Millions of dollars)

 

2011

 

2010

 

Assets

 

 

 

 

 

Utility Plant In Service

 

$

12,000

 

$

11,714

 

Accumulated Depreciation and Amortization

 

(3,836

)

(3,495

)

Construction Work in Progress

 

1,482

 

1,081

 

Nuclear Fuel, Net of Accumulated Amortization

 

171

 

132

 

Goodwill, Net of Writedown of $276

 

230

 

230

 

 

 

 

 

 

 

Utility Plant, Net

 

10,047

 

9,662

 

 

 

 

 

 

 

Nonutility Property and Investments:

 

 

 

 

 

Nonutility property, net of accumulated depreciation of $131 and $118

 

305

 

299

 

Assets held in trust, net-nuclear decommissioning

 

84

 

76

 

Other investments

 

87

 

78

 

Nonutility Property and Investments, Net

 

476

 

453

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

Cash and cash equivalents

 

29

 

55

 

Receivables, net of allowance for uncollectible accounts of $6 and $9

 

756

 

837

 

Inventories (at average cost):

 

 

 

 

 

Fuel

 

313

 

316

 

Materials and supplies

 

129

 

125

 

Emission allowances

 

2

 

6

 

Prepayments and other

 

236

 

271

 

Deferred income taxes

 

26

 

21

 

Total Current Assets

 

1,491

 

1,631

 

 

 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

 

 

Regulatory assets

 

1,279

 

1,061

 

Other

 

241

 

161

 

Total Deferred Debits and Other Assets

 

1,520

 

1,222

 

 

 

 

 

 

 

Total

 

$

13,534

 

$

12,968

 

December 31, (Millions of dollars) 2013 2012
Assets  
  
Utility Plant In Service $12,213
 $11,865
Accumulated Depreciation and Amortization (4,011) (3,811)
Construction Work in Progress 2,724
 2,084
Plant to be Retired, Net 177
 362
Nuclear Fuel, Net of Accumulated Amortization 310
 166
Goodwill 230
 230
Utility Plant, Net 11,643
 10,896
Nonutility Property and Investments:  
  
Nonutility property, net of accumulated depreciation of $150 and $139 317
 306
Assets held in trust, net-nuclear decommissioning 101
 94
Other investments 86
 87
Nonutility Property and Investments, Net 504
 487
Current Assets:  
  
Cash and cash equivalents 136
 72
Receivables, net of allowance for uncollectible accounts of $6 and $7 802
 780
Inventories:  
  
Fuel 231
 304
Materials and supplies 131
 136
Emission allowances 1
 1
Prepayments and other 120
 223
Deferred income taxes 
 11
Total Current Assets 1,421
 1,527
Deferred Debits and Other Assets:  
  
Regulatory assets 1,360
 1,464
Pension asset 47
 
Other 189
 242
Total Deferred Debits and Other Assets 1,596
 1,706
Total $15,164
 $14,616
See Notes to Consolidated Financial Statements.

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SCANA Corporation

CONSOLIDATED BALANCE SHEETS

December 31, (Millions of dollars)

 

2011

 

2010

 

Capitalization and Liabilities

 

 

 

 

 

Common equity

 

$

3,889

 

$

3,702

 

Long-Term Debt, Net

 

4,622

 

4,152

 

Total Capitalization

 

8,511

 

7,854

 

Current Liabilities:

 

 

 

 

 

Short-term borrowings

 

653

 

420

 

Current portion of long-term debt

 

31

 

337

 

Accounts payable

 

374

 

526

 

Customer deposits and customer prepayments

 

103

 

100

 

Taxes accrued

 

154

 

146

 

Interest accrued

 

74

 

72

 

Dividends declared

 

63

 

61

 

Derivative financial instruments

 

77

 

65

 

Other

 

113

 

140

 

Total Current Liabilities

 

1,642

 

1,867

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

Deferred income taxes, net

 

1,533

 

1,391

 

Deferred investment tax credits

 

40

 

56

 

Asset retirement obligations

 

474

 

497

 

Pension and other postretirement benefits

 

291

 

202

 

Regulatory liabilities

 

778

 

913

 

Other

 

265

 

188

 

Total Deferred Credits and Other Liabilities

 

3,381

 

3,247

 

Commitments and Contingencies (Note 10)

 

 

 

Total

 

$

13,534

 

$

12,968

 

December 31, (Millions of dollars) 2013 2012
Capitalization and Liabilities  
  
Common equity $4,664
 $4,154
Long-Term Debt, Net 5,395
 4,949
Total Capitalization 10,059
 9,103
Current Liabilities:  
  
Short-term borrowings 376
 623
Current portion of long-term debt 54
 172
Accounts payable 425
 428
Customer deposits and customer prepayments 88
 86
Taxes accrued 206
 164
Interest accrued 82
 82
Dividends declared 69
 66
Derivative financial instruments 8
 80
Other 134
 110
Total Current Liabilities 1,442
 1,811
Deferred Credits and Other Liabilities:  
  
Deferred income taxes, net 1,703
 1,653
Deferred investment tax credits 32
 36
Asset retirement obligations 576
 561
Postretirement benefits 227
 387
Regulatory liabilities 966
 882
Other 159
 183
Total Deferred Credits and Other Liabilities 3,663
 3,702
Commitments and Contingencies (Note 10) 
 
Total $15,164
 $14,616
See Notes to Consolidated Financial Statements.

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SCANA Corporation

CONSOLIDATED STATEMENTS OF INCOME

Years Ended December 31, (Millions of dollars, except per share amounts)

 

2011

 

2010

 

2009

 

Operating Revenues:

 

 

 

 

 

 

 

Electric

 

$

2,424

 

$

2,367

 

$

2,141

 

Gas-regulated

 

849

 

989

 

958

 

Gas-nonregulated

 

1,136

 

1,245

 

1,138

 

Total Operating Revenues

 

4,409

 

4,601

 

4,237

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

Fuel used in electric generation

 

917

 

942

 

818

 

Purchased power

 

19

 

17

 

17

 

Gas purchased for resale

 

1,455

 

1,679

 

1,570

 

Other operation and maintenance

 

658

 

670

 

640

 

Depreciation and amortization

 

346

 

335

 

316

 

Other taxes

 

201

 

190

 

177

 

Total Operating Expenses

 

3,596

 

3,833

 

3,538

 

 

 

 

 

 

 

 

 

Operating Income

 

813

 

768

 

699

 

 

 

 

 

 

 

 

 

Other Income (Expense):

 

 

 

 

 

 

 

Other income

 

52

 

52

 

67

 

Other expenses

 

(40

)

(39

)

(37

)

Interest charges, net of allowance for borrowed funds used during construction of $7, $10 and $23

 

(284

)

(266

)

(233

)

Allowance for equity funds used during construction

 

14

 

20

 

28

 

Total Other Expense

 

(258

)

(233

)

(175

)

 

 

 

 

 

 

 

 

Income Before Income Tax Expense

 

555

 

535

 

524

 

Income Tax Expense

 

168

 

159

 

167

 

Net Income

 

387

 

376

 

357

 

Less Preferred Stock Dividends of Subsidiary

 

 

 

(9

)

Income Available to Common Shareholders of SCANA

 

$

387

 

$

376

 

$

348

 

 

 

 

 

 

 

 

 

Per Common Share Data

 

 

 

 

 

 

 

Basic Earnings Per Share of Common Stock

 

$

3.01

 

$

2.99

 

$

2.85

 

Diluted Earnings Per Share of Common Stock

 

2.97

 

2.98

 

2.85

 

Weighted Average Common Shares Outstanding (millions)

 

 

 

 

 

 

 

Basic

 

128.8

 

125.7

 

122.1

 

Diluted

 

130.2

 

126.3

 

122.2

 

Dividends Declared Per Share of Common Stock

 

$

1.94

 

$

1.90

 

$

1.88

 

Years Ended December 31, (Millions of dollars, except per share amounts) 2013 2012 2011
Operating Revenues:  
  
  
Electric $2,423
 $2,446
 $2,424
Gas-regulated 955
 774
 849
Gas-nonregulated 1,117
 956
 1,136
Total Operating Revenues 4,495
 4,176
 4,409
       
Operating Expenses:  
  
  
Fuel used in electric generation 745
 838
 917
Purchased power 43
 28
 19
Gas purchased for resale 1,491
 1,198
 1,455
Other operation and maintenance 708
 690
 658
Depreciation and amortization 378
 356
 346
Other taxes 220
 207
 201
Total Operating Expenses 3,585
 3,317
 3,596
       
Operating Income 910
 859
 813
       
Other Income (Expense):  
  
  
Other income 100
 59
 52
Other expenses (46) (42) (40)
Interest charges, net of allowance for borrowed funds used during construction of $14, $11 and $7 (297) (295) (284)
Allowance for equity funds used during construction 27
 21
 14
Total Other Expense (216) (257) (258)
       
Income Before Income Tax Expense 694
 602
 555
Income Tax Expense 223
 182
 168
Net Income $471
 $420
 $387
       
Per Common Share Data  
  
  
Basic Earnings Per Share of Common Stock $3.40
 $3.20
 $3.01
Diluted Earnings Per Share of Common Stock 3.39
 3.15
 2.97
Weighted Average Common Shares Outstanding (millions)  
  
  
Basic 138.7
 131.1
 128.8
Diluted 139.1
 133.3
 130.2
See Notes to Consolidated Financial Statements.

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SCANA Corporation

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Years Ended December 31, (Millions of dollars) 2013 2012 2011 
Net Income $471
 $420
 $387
 
Other Comprehensive Income (Loss), net of tax:       
Unrealized Losses on Cash Flow Hedging Activities:       
Unrealized gains (losses) on cash flow hedging activities arising during period, net of tax of $4, $(5) and $(36) 7
 (8) (58) 
Losses on cash flow hedging activities reclassified to net income, net of tax of $7, $12 and $8 11
 19
 13
 
Net unrealized gains (losses) on cash flow hedging activities 18
 11
 (45) 
Deferred Costs of Employee Benefit Plans:       
Deferred costs of employee benefit plans, net of tax of $4, $(2) and $(2) 7
 (4) (3) 
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax of $-, $- and $- 1
 1
 1
 
Net deferred costs of employee benefit plans 8
 (3) (2) 
Other Comprehensive Income (Loss) 26
 8
 (47) 
Total Comprehensive Income $497
 $428
 $340
 
See Notes to Consolidated Financial Statements.


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SCANA Corporation
CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, (Millions of dollars)

 

2011

 

2010

 

2009

 

Cash Flows From Operating Activities:

 

 

 

 

 

 

 

Net Income

 

$

387

 

$

376

 

$

357

 

Adjustments to reconcile net income to net cash provided from operating activities:

 

 

 

 

 

 

 

Earnings from equity method investments, net of distributions

 

2

 

3

 

1

 

Deferred income taxes, net

 

164

 

240

 

93

 

Depreciation and amortization

 

354

 

341

 

329

 

Amortization of nuclear fuel

 

40

 

36

 

18

 

Allowance for equity funds used during construction

 

(14

)

(20

)

(28

)

Carrying cost recovery

 

 

(3

)

(5

)

Cash provided (used) by changes in certain assets and liabilities:

 

 

 

 

 

 

 

Receivables

 

34

 

(143

)

134

 

Inventories

 

(44

)

11

 

(76

)

Prepayments and other

 

58

 

(109

)

64

 

Regulatory assets

 

(173

)

(71

)

(82

)

Regulatory liabilities

 

(17

)

(13

)

(6

)

Accounts payable

 

(99

)

79

 

(46

)

Taxes accrued

 

8

 

12

 

6

 

Interest accrued

 

2

 

1

 

2

 

Changes in other assets

 

34

 

(32

)

(36

)

Changes in other liabilities

 

75

 

103

 

(46

)

Net Cash Provided From Operating Activities

 

811

 

811

 

679

 

Cash Flows From Investing Activities:

 

 

 

 

 

 

 

Property additions and construction expenditures

 

(884

)

(876

)

(914

)

Proceeds from investments (including derivative collateral posted)

 

36

 

104

 

31

 

Purchase of investments (including derivative collateral posted)

 

(168

)

(102

)

(6

)

Settlements of interest rate contracts

 

(61

)

 

 

Net Cash Used For Investing Activities

 

(1,077

)

(874

)

(889

)

Cash Flows From Financing Activities:

 

 

 

 

 

 

 

Proceeds from issuance of common stock

 

97

 

149

 

191

 

Proceeds from issuance of long-term debt

 

826

 

259

 

600

 

Repayments of long-term debt

 

(668

)

(300

)

(599

)

Redemption/repurchase of equity securities

 

 

 

(113

)

Dividends

 

(248

)

(237

)

(234

)

Short-term borrowings, net

 

233

 

85

 

255

 

Net Cash Provided From (Used For) Financing Activities

 

240

 

(44

)

100

 

Net Decrease in Cash and Cash Equivalents

 

(26

)

(107

)

(110

)

Cash and Cash Equivalents, January 1

 

55

 

162

 

272

 

Cash and Cash Equivalents, December 31

 

$

29

 

$

55

 

$

162

 

Supplemental Cash Flow Information:

 

 

 

 

 

 

 

Cash paid for—Interest (net of capitalized interest of $7, $9 and $23)

 

$

276

 

$

268

 

$

233

 

 

—Income taxes

 

6

 

61

 

79

 

Noncash Investing and Financing Activities:

 

 

 

 

 

 

 

Accrued construction expenditures

 

85

 

179

 

160

 

Capital leases

 

6

 

6

 

 

For the Years Ended December 31, (Millions of dollars) 2013 2012 2011
Cash Flows From Operating Activities:  
  
  
Net Income $471
 $420
 $387
Adjustments to reconcile net income to net cash provided from operating activities:  
  
  
Earnings from equity method investments, net of distributions 7
 
 2
  Deferred income taxes, net 49
 130
 164
Depreciation and amortization 393
 368
 354
Amortization of nuclear fuel 57
 44
 40
Allowance for equity funds used during construction (27) (21) (14)
Carrying cost recovery (3) 
 
Changes in certain assets and liabilities:  
  
  
Receivables (38) 5
 34
Inventories 21
 (53) (44)
Prepayments and other (12) 3
 58
Regulatory assets 113
 (172) (173)
Regulatory liabilities 56
 62
 (17)
Accounts payable 24
 34
 (99)
Taxes accrued 42
 10
 8
Interest accrued 
 8
 2
Pension and other postretirement benefits (217) 89
 90
     Other assets 78
 (120) 34
     Other liabilities 36
 32
 (15)
Net Cash Provided From Operating Activities 1,050
 839
 811
Cash Flows From Investing Activities:  
  
  
Property additions and construction expenditures (1,106) (1,077) (884)
Proceeds from investments (including derivative collateral posted) 222
 472
 36
Purchase of investments (including derivative collateral posted) (176) (414) (168)
Payments upon interest rate derivative contract settlement (49) (51) (61)
  Proceeds from interest rate derivative contract settlement 163
 14
 
Net Cash Used For Investing Activities (946) (1,056) (1,077)
Cash Flows From Financing Activities:  
  
  
Proceeds from issuance of common stock 295
 97
 97
Proceeds from issuance of long-term debt 451
 759
 826
Repayments of long-term debt (258) (309) (668)
Dividends (281) (257) (248)
Short-term borrowings, net (247) (30) 233
Net Cash Provided From (Used For) Financing Activities (40) 260
 240
Net Increase (Decrease) in Cash and Cash Equivalents 64
 43
 (26)
Cash and Cash Equivalents, January 1 72
 29
 55
Cash and Cash Equivalents, December 31 $136
 $72
 $29
Supplemental Cash Flow Information:  
  
  
Cash paid for—Interest (net of capitalized interest of $14, $11 and $7) $288
 $281
 $276
                      —Income taxes 104
 107
 6
Noncash Investing and Financing Activities:  
  
  
Accrued construction expenditures 111
 124
 85
Capital leases 6
 8
 6
Nuclear fuel purchase 98
 
 
See Notes to Consolidated Financial Statements.

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SCANA Corporation

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY AND

        Accumulated  
        Other  
  Common Stock Retained Comprehensive  
Millions Shares Amount Earnings Loss Total
Balance as of January 1, 2011 127
 $1,789
 $1,960
 $(47) $3,702
Net Income     387
   387
Other Comprehensive Loss, net of taxes of $(29)       (47) (47)
Total Comprehensive Income (Loss)     387
 (47) 340
Issuance of Common Stock 3
 97
     97
Dividends Declared     (250)   (250)
Balance as of December 31, 2011 130
 1,886
 2,097
 (94) 3,889
Net Income     420
   420
Other Comprehensive Income, net of taxes of $5       8
 8
Total Comprehensive Income     420
 8
 428
Issuance of Common Stock 2
 97
     97
Dividends Declared     (260)   (260)
Balance as of December 31, 2012 132
 1,983
 2,257
 (86) 4,154
Net Income     471
   471
Other Comprehensive Income, net of taxes of $16       26
 26
Total Comprehensive Income     471
 26
 497
Issuance of Common Stock 9
 297
     297
Dividends Declared     (284)   (284)
Balance as of December 31, 2013 141
 $2,280
 $2,444
 $(60) $4,664

Dividends declared per share of common stock were

COMPREHENSIVE INCOME$2.03

 

 

Common Stock

 

Retained

 

Accumulated
Other
Comprehensive

 

 

 

Millions

 

Shares

 

Amount

 

Earnings

 

Income (Loss)

 

Total

 

Balance as of January 1, 2009

 

118

 

$

1,449

 

$

1,705

 

$

(109

)

$

3,045

 

Comprehensive Income:

 

 

 

 

 

 

 

 

 

 

 

Income available to common shareholders of SCANA

 

 

 

 

 

348

 

 

 

348

 

Other comprehensive income, net of taxes $33

 

 

 

 

 

 

 

54

 

54

 

Total Comprehensive Income

 

 

 

 

 

348

 

54

 

402

 

Issuance of Common Stock

 

5

 

191

 

 

 

 

 

191

 

Dividends Declared on Common Stock

 

 

 

 

 

(230

)

 

 

(230

)

Balance as of December 31, 2009

 

123

 

$

1,640

 

$

1,823

 

$

(55

)

$

3,408

 

Comprehensive Income:

 

 

 

 

 

 

 

 

 

 

 

Income available to common shareholders of SCANA

 

 

 

 

 

376

 

 

 

376

 

Other comprehensive income, net of taxes $5

 

 

 

 

 

 

 

8

 

8

 

Total Comprehensive Income

 

 

 

 

 

376

 

8

 

384

 

Issuance of Common Stock

 

4

 

149

 

 

 

 

 

149

 

Dividends Declared on Common Stock

 

 

 

 

 

(239

)

 

 

(239

)

Balance as of December 31, 2010

 

127

 

$

1,789

 

$

1,960

 

$

(47

)

$

3,702

 

Comprehensive Income (Loss):

 

 

 

 

 

 

 

 

 

 

 

Income available to common shareholders of SCANA

 

 

 

 

 

387

 

 

 

387

 

Other comprehensive loss, net of taxes $(29)

 

 

 

 

 

 

 

(47

)

(47

)

Total Comprehensive Income (Loss)

 

 

 

 

 

387

 

(47

)

340

 

Issuance of Common Stock

 

3

 

97

 

 

 

 

 

97

 

Dividends Declared on Common Stock

 

 

 

 

 

(250

)

 

 

(250

)

Balance as of December 31, 2011

 

130

 

$

1,886

 

$

2,097

 

$

(94

)

$

3,889

 

, $1.98 and $1.94 for 2013, 2012 and 2011, respectively.


See Notes to Consolidated Financial Statements.

58




54





Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.             SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Principles of Consolidation

SCANA, a South Carolina corporation, is a holding company. The Company engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia. The Company also conducts other energy-related business and provides fiber optic communications in South Carolina.

The accompanying Consolidated Financial Statementsconsolidated financial statements reflect the accounts of SCANA and the following wholly-owned subsidiaries, and two other wholly-owned subsidiaries liquidated in 2011.

subsidiaries.

Regulated businesses

Nonregulated businesses

Regulated businessesNonregulated businesses
South Carolina Electric & Gas Company

SCANA Energy Marketing, Inc.

South Carolina Fuel Company, Inc.

SCANA Communications, Inc.

South Carolina Generating Company, Inc.

ServiceCare, Inc.

Public Service Company of North Carolina, Incorporated

SCANA Services, Inc.

Carolina Gas Transmission Corporation

SCANA Corporate Security Services, Inc.

Westex Holdings, LLC

The Company reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation, with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable, as permitted by accounting guidance.

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.

Utility Plant

Utility plant is stated substantially at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and an allowance for funds used during construction,AFC, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense.

AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using average composite rates of 6.9% for 2013, 6.3% for 2012 and 4.7% for 2011, 7.4% for 2010 and 7.5% for 2009.2011. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561.rates allowed in the various regulatory jurisdictions. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.


55




The Company records provisions for depreciation and amortization using the straight-line method based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were as follows:

 

 

2011

 

2010

 

2009

 

SCE&G

 

2.92

%

2.83

%

2.97

%

GENCO

 

2.69

%

2.66

%

2.66

%

CGT

 

2.00

%

1.94

%

1.94

%

PSNC Energy

 

3.05

%

3.11

%

3.10

%

Aggregate of Above

 

2.90

%

2.85

%

2.95

%

59


 2013 2012 2011
SCE&G2.96% 2.93% 2.92%
GENCO2.66% 2.66% 2.69%
CGT2.19% 2.09% 2.00%
PSNC Energy3.01% 3.01% 3.05%
Aggregate of Above2.93% 2.90% 2.90%

Table of Contents

SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in “Fuel used in electric generation” and recovered through the fuel cost component of retail electric rates. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the DOE under a contract for disposal of spent nuclear fuel.


Jointly Owned Utility Plant

SCE&G jointly owns and is the operator of Summer Station Unit 1.  In addition, SCE&G will jointly own and will be the operator of the New Units being designed and constructed at the site of Summer Station.  Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership of a unit.  SCE&G’s share of the direct expenses areis included in the corresponding operating expenses on its income statement.

 

 

Unit 1

 

New Units

 

As of December 31, 2011

 

 

 

 

 

Percent owned

 

66.7

%

55.0

%

Plant in service

 

$

1.0 billion

 

 

Accumulated depreciation

 

$

545.0 million

 

 

Construction work in progress

 

$

71.0 million

 

$

1.2 billion

 

 

 

 

 

 

 

As of December 31, 2010

 

 

 

 

 

Percent owned

 

66.7

%

55.0

%

Plant in service

 

$

1.0 billion

 

 

Accumulated depreciation

 

$

548.8 million

 

 

Construction work in progress

 

$

40.1 million

 

$

891.2 million

 

As of December 31,2013 2012
 Unit 1 New Units Unit 1 New Units
Percent owned66.7% 55.0% 66.7% 55.0%
Plant in service$1.1 billion  $1.1 billion 
Accumulated depreciation$566.9 million  $557.0 million 
Construction work in progress$127.1 million $2.3 billion $113.6 million $1.8 billion
SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals approximately $6.0$5.4 billion for plant costs and for related transmission infrastructure costs, and is projected based on historical one-yearone-year and five year-year escalation rates as required by the SCPSC.

SCE&G’s latest Integrated Resource Plan filed with the SCPSC in February 2011 continues to support SCE&G’s need for 55 percent For a discussion of the output ofwhen the New Units.  As previously reported,Units are expected to be placed in service, and a description of SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation&G's agreement to acquire an additional 5% ownership in the New Units.  Santee Cooper has entered into a letter of intent with Duke that may result in Duke acquiring a portion of Santee Cooper’s ownership interest in the New Units.   SCE&G is unable to predict whether any change in Santee Cooper’s ownership interest or the addition of new joint owners will increase project costs or delay the commercial operation dates of the New Units.  Any such project cost increase or delay could be material.

The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude.  During the course of activities under the EPC Contract, issues have materialized that may impact project budget and schedule, including those related to COL delays, design modifications of the shield building and certain pre-fabricated modules for the New Units, and unanticipated rock conditions at the site.  These issues have resulted in assertions of contractual entitlement to recover additional costs and may result in requests for change orders from the Consortium.  While SCE&G has not accepted the validity of any claims, the total amount of the claims presented (SCE&G’s portion in 2007 dollars) is approximately $188 million.  SCE&G expects to resolve any such disputes through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time (seesee Note 2 to the consolidated financial statements), will be recoverable through rates.

10.

Included within receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for Summer Station Unit 1 and the New Units. These amounts totaled $63.6$75.6 million at December 31, 20112013 and $77.9$92.9 million at December 31, 2010.

2012.


Plant to be Retired

As previously disclosed, in 2012 SCE&G identified a total of six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. As of December 31, 2013, three of these units had been retired and their net carrying value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC.


56



Major Maintenance


Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections are classified as a regulatory asset or regulatory liability on the consolidated balance sheet (see Note 2). Other planned major maintenance is expensed when incurred.
Through 2017, SCE&G is authorized to collect $18.4$18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the yearyears ended December 31, 2011,2013 and 2012, SCE&G incurred $11.5$18.1 million and $11.1 million, respectively, for turbine maintenance. Cumulative


60



Table of Contents

costs for turbine maintenance in excess of cumulative collections are classified as a regulatory asset on the balance sheet. Nuclear refueling outages are scheduled 18 months apart, and SCE&G begins accruing for each successive scheduled outage upon completion of the preceding scheduled outage.apart. SCE&G accrued $1.2$1.2 million per month from July 2008January 2010 through July 2011December 2012 for its portion of the outages in the spring of 2011 and the fall of 2009 and the spring of 2011.2012. Total costs for the 20092011 outage were $32.7$34.1 million, of which SCE&G was responsible for $21.8 million.$22.7 million. Total costs for the 20112012 outage were $34.1$32.3 million, of which SCE&G was responsible for $22.7 million.$21.5 million. In July 2011,connection with the SCPSC's December 2012 approval of SCE&G's retail electric rates (see Note 2), effective January 1, 2013, SCE&G began accruing $1.2to accrue $1.4 million per month for its portion of the nuclear refueling planned foroutages that are scheduled to occur through the fallspring of 2012.  SCE&G had an accrued balance of $7.2 million at December 31, 2011 and $14.3 million at December 31, 2010.

2020.

Goodwill
Goodwill

The Company considers amounts categorized by FERC as “acquisition adjustments” with carrying values of $210$210 million (net of writedown of $230 million) for PSNC Energy (Gas Distribution segment) and $20$20 million for CGT (All Other segment) to be goodwill. The Company tests these goodwill amounts for impairment annually as of January 1, unless indicators, events or circumstances require interim testing to be performed.  The goodwill impairment testing is generally a two-step quantitative process which in step one requires estimation of the fair value of the respective reporting unit and the comparison of that amount to theits carrying value of the reporting unit.value. If this step indicates an impairment (a carrying value in excess of fair value), then step two, measurement of the amount of the goodwill impairment (if any), is required.  In the first quarter of 2012, the Company will adopt accountingadopted guidance wherebyunder which it will havehas the option to first perform a qualitative assessment of impairment.  Based on this qualitative ("step zero") assessment, if the Company determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company willis not be required to proceed with the two-step quantitative assessment.

In evaluations of PSNC Energy, fair value iswas estimated using the assistance of an independent appraisal. In evaluations of CGT, prior to the adoption of the new guidance, estimated fair value has beenwas obtained from internal analyses.discounted cash flow and other analysis. Step zero was utilized for CGT’s evaluation as of January 1, 2013, and step one (via discounted cash flow and other analysis) was again utilized for the evaluation as of January 1, 2014. In all evaluations for the periods presented, step one or step zero, as applicable, has indicated no impairment,impairment. The estimated fair values of the reporting units are substantially in excess of their carrying values, and no impairment charges have been recorded; however, should a write-down be required in the future, such a charge would be treated as an operating expense.

Nuclear Decommissioning

SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $451.0$696.8 million, stated in 2006 dollars.2012 dollars, pursuant to an updated decommissioning cost study performed in 2012. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station Unit 1. The cost estimate assumes that the site wouldwill be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use.

Under SCE&G’s method of funding decommissioning costs, amounts collected through rates ($($3.2 million pre-tax in each of 2011, 20102013, 2012 and 2009)2011) are invested in insurance policies on the lives of certain Company personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Summer Station Unit 1 on an after-tax basis.


57



Cash and Cash Equivalents

The Company considers temporary cash investments having original maturities of three months or less at time of purchase to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements and treasury bills and notes.

Accountbills.

Accounts Receivable

Accounts receivable reflect amounts due from customers arising from the delivery of energy or related services and include revenues earned pursuant to revenue recognition practices described below. These receivables include both billed and unbilled amounts. Receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis.

61



Inventory

TableMaterials and supplies include the average cost of Contents

transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas and fuel oil. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC or NCUC, as applicable. Emission allowances are included in inventory at average cost. Emission allowances are expensed at weighted average cost as used and recovered through fuel cost recovery rates approved by the SCPSC.


Asset Management and Supply Service Agreements

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities. At December 31, 2011, suchSuch counterparties held 45%48% and 44% of PSNC Energy’s natural gas inventory at December 31, 2013 and December 31, 2012, respectively, with a carrying value of $28.7$22.8 million and $19.6 million, respectively, through either capacity release or agency relationships. Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees.  No fees are received under supply service agreements. The agreements expire at various times through March 31, 2013.

2015.

Income Taxes

The Company files a consolidated federal income tax return. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, they are charged or credited to income tax expense.

Regulatory Assets and Regulatory Liabilities

The Company’s rate-regulated utilities record costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense or revenues would be recognized by a nonregulated enterprise. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the balance sheet as regulatory assets and regulatory liabilities (See(see Note 2). The regulatory assets and liabilities are amortized consistent with the treatment of the related costs in the ratemaking process.

Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt

The Company records long-term debt premium and discount within long-term debt and amortizes them as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges.

Environmental

The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued

58



when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in deferred debitsregulatory assets and, if applicable, amortized over approved amortization periods.  Other environmental costs are recorded to expense.

expense as incurred.


Income Statement Presentation

In its consolidated statements of income, the Company presents the activitiesrevenues and expenses of its regulated businesses and significant nonregulatedits retail natural gas marketing businesses (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense).


Revenue Recognition

The Company records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered but not yet billed. Unbilled revenues totaled $169.1$183.1 million at December 31, 20112013 and $221.1$189.8 million at December 31, 2010.

622012.




Table of Contents

Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. This component is established by the SCPSC during annual fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during the next annual hearing.

subsequent hearings.

SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs including the results of its hedging program, and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews.

SCE&G’s gas rate schedules for residential, small commercial and small industrial customers include a WNA which minimizes fluctuations in gas revenues due to abnormal weather conditions. In August 2010, SCE&G implemented an eWNA on a one-year pilot basis for its electric customers, and it will continue on a pilot basis unless modified or terminatedcustomers; effective with the first billing cycle of 2014, the eWNA was discontinued as approved by the SCPSC.

See Note 2.

PSNC Energy is authorized by the NCUC to utilize a CUT which allows it to adjust base rates semi-annually for residential and commercial customers based on average per customer consumption, whether impacted by weather or other factors.

Taxes that are billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Accordingly, no suchSuch taxes are not included in revenues or expenses in the statements of income.

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. The Company usesstock utilizing the treasury stock method in determining total dilutive potential common stock.method. The Company has issued no securities that would have an antidilutive effect on earnings per share.

A reconciliation of the weighted average number of common shares for each of the three years ended December 31, 2011 for basic and diluted purposes is as follows:

In Millions

 

2011

 

2010

 

2009

 

Weighted Average Shares Outstanding—Basic

 

128.8

 

125.7

 

122.1

 

Net effect of dilutive stock-based compensation plans and equity forward contracts

 

1.4

 

0.6

 

0.1

 

Weighted Average Shares Outstanding—Diluted

 

130.2

 

126.3

 

122.2

 

New Accounting Matters

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

Effective for the first quarter of 2012, the Company will adopt accounting guidance that permits it to make a qualitative assessment about the likelihood of goodwill impairment each year.  The results of such an assessment may lead the Company to determine that performing a two-step quantitative impairment test is unnecessary.  The Company does not expect the adoption of this guidance to impact results of operations, cash flows or financial position.

63

In Millions 2013 2012 2011
Weighted Average Shares Outstanding—Basic 138.7
 131.1
 128.8
Net effect of equity forward contracts 0.4
 2.2
 1.4
Weighted Average Shares Outstanding—Diluted 139.1
 133.3
 130.2


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Table of Contents

2.             RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric - Cost of Fuel

Electric

SCE&G’s&G's retail electric rates are established in part by usinginclude 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. EffectiveIn April 2012, the SCPSC approved SCE&G's request to decrease the total fuel cost component of its retail electric rates, and approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to recover an amount equal to its actual under-collected balance of base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a twelve month period beginning with the first billing cycle of May 2010,2012.


This April 2012 order was superseded, in part, by a December 2012 rate order in which the SCPSC approved a settlement agreement authorizingauthorized SCE&G to decreasereduce the fuel cost portion of its electric rates.  The settlement agreement incorporated SCE&G’s proposal to accelerate the recognition of $17.4 million of previously deferred state income tax credits and record an offsetting reduction to the recovery of fuel costs.  In addition, SCE&G agreed to defer recovery of its actual undercollected base fuel costs as of April 30, 2010 until May 2011.  SCE&G was allowed to charge and accrue carrying costs monthly on the actual base fuel costs undercollected balance as of the end of each month during this deferral period.  In February 2011, SCE&G requested authorization to increase the cost of fuel component of its retail electric rates and, in doing so, stated that SCE&G may not adjust its base fuel cost component prior to bethe last billing cycle of April 2014 except where necessary due to extraordinary unforeseen economic or financial conditions.  In February 2013, in connection with its annual review of base rates for fuel costs, SCE&G requested authorization to reduce its environmental fuel cost component effective with the first billing cycle of May 2011.  On2013.  Consistent with the December 2012 rate order,SCE&G did not request any adjustment to its base fuel cost component.  In March 17, 2011,2013, SCE&G, ORS and the SCEUC entered into a settlement agreement in which SCE&G agreed to recover its actual baseaccepting the proposed lower environmental fuel under-collected balance as of April 30, 2011 over a two-year period commencing with the first billing cycle of May 2011.  The settlement agreement also provided that SCE&G would be allowed to charge and accrue carrying costs monthly on the deferred balance.  By order dated April 26, 2011, the SCPSC approved the settlement agreement.  In February 2012, SCE&G requested authorization to decrease the cost of fuel component of its retail electric rates effective with the first billing cycle of May 2012.2013, and providing for the accrual of certain debt-related carrying costs on a portion of the under-collected balance of fuel costs. The nextSCPSC issued an order dated April 30, 2013, adopting and approving the settlement agreement and approving SCE&G's total fuel cost component. A public hearing for the annual hearing to review of base rates for fuel costs ishas been scheduled for March 22, 2012.

On July 15, 2010,April 3, 2014.


Pursuant to a November 2013 SCPSC accounting order, the Company's electric revenue for 2013 was reduced for adjustments to the fuel cost component and related under-collected fuel balance of $41.6 million. Such adjustments are fully offset by the recognition within other income, also pursuant to that accounting order, of gains realized upon the 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. See also Note 6.

Electric - Base Rates

In October 2013, SCE&G received an accounting order from the SCPSC issued an order approvingdirecting 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 4.88%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 during 2013, $2.9 million of such carrying costs were accrued within other income. SCE&G anticipates that when the New Units are placed in service and accelerated tax deprecation is recognized on them, these deferred income tax assets will decline.  When these 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.

In December 2012, the SCPSC approved a 4.23% overall increase in SCE&G’s&G's retail electric base rates, effective January 1, 2013, and authorized an allowed return on common equity of 10.7%10.25%. AmongThe SCPSC also approved a mid-period reduction to the cost of fuel component in rates (as discussed above), a reduction in the DSM Programs component rider to retail rates, and the recovery of and a return on the net carrying value of certain retired generating plant assets described below. In February 2013, the SCPSC denied the SCEUC's petition for rehearing and the denial was not appealed.
The eWNA was designed to mitigate the effects of abnormal weather on residential and commercial customers' bills and had been in use since August 2010. In connection with the December 2012 order, SCE&G agreed to perform a study of alternative structures for eWNA. On November 1, 2013, the ORS filed a report with the SCPSC recommending that the eWNA be terminated with the last billing cycle for December 2013. On November 26, 2013, SCE&G, ORS and certain other parties filed a joint petition with the SCPSC requesting, among other things, that the SCPSC’s order (1) included implementationSCPSC discontinue the eWNA effective with bills rendered on or after the first billing cycle of January 2014. On December 20, 2013, the SCPSC granted the relief requested in the joint petition.

In connection with the above termination of the eWNA program effective December 31, 2013, electric revenues were reduced to reverse the prior accrual of an under-collected balance of $8.5 million. Pursuant to the SCPSC accounting order granting the above relief and terminating the eWNA, for such revenue reduction was fully offset by the recognition within other

60



income of $8.5 million of gains realized upon the 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.

SCE&G’s&G files an IRP with the SCPSC annually which evaluates future electric customers, which begangeneration needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G's 2012 IRP identified six coal-fired units that SCE&G has subsequently retired or intends to retire by 2018, subject to future developments in Augustenvironmental regulations, among other matters. One of these units was retired in 2012, and two others were retired in the fourth quarter of 2013. The net carrying value of these retired units is recorded in regulatory assets as unrecovered plant and is being amortized over the units' previously estimated remaining useful lives as approved by the SCPSC. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. 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.

In a July 2010 (2)order, the SCPSC provided for a $25$48.7 million credit, over one year, to SCE&G’s customers to be offset by amortization of weather-related revenues which were deferred in the first quarter of 2010 pursuant to a stipulation between SCE&G and the ORS, (3) provided for a $48.7 million credit to SCE&G’s&G's customers over two years to be offset by accelerated recognition of previously deferred state income tax credits. These tax credits and (4) provided for the recovery of certain federally-mandated capital expenditures that had been includedwere fully amortized in utility plant but were not being depreciated.

On July 15, 2010, the SCPSC issued an order approving the implementation by 2012.


SCE&G of certain&G's DSM Programs including the establishment offor electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and lost net margin revenue associated with the DSM Programs, along with an incentive for investing in such programs. The SCPSC’s order approved various settlement agreements among SCE&G the ORS and other intervening parties. On July 27, 2010, SCE&G filed the rate rider tariff sheet for DSM Programs with the SCPSC. The tariff rider was applied to bills rendered on or after October 30, 2010. The order requires that SCE&G submitsubmits annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC has approved the following rate changes pursuant to annual DSM Programs filings, which went into effect as indicated below:
YearEffectiveAmount
2013First billing cycle of May$16.9 million
2012First billing cycle of May$19.6 million
2011First billing cycle of June$7.0 million

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

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

In November 2013 the SCPSC approved SCE&G’s continued use of DSM programs for another six years, including approval of the rate rider mechanism and a revised portfolio of DSM programs.

In January 2011,2014 SCE&G submitted its annual DSM Programs filing to the SCPSC, its annual updatewhich included, among other things, a request to (1) recover one-half of the balance of allowable costs beginning with bills rendered on DSM Programs.  Included in the filing was a petition to update the rate rider to provide for the recovery of costs, lost net margin revenue, and the approved shared savings incentive for investing in such DSM Programs.  By order dated May 24, 2011, the SCPSC approved the updated rate rider and authorized SCE&G to increase its rates for DSM Programs as set forth in its petition.  The increase became effectiveafter the first billing cycle of June 2011.  In January 2012,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 recent settlement of certain interest rate derivative instruments to offset a portion of the net lost revenues component of SCE&G submitted&G’s DSM Programs rider, and (3) apply $5 million of its storm damage reserve and a portion of the gains from the recent settlement of certain interest rate derivative instruments, currently estimated to be $5.5 million, to the SCPSC its annual update on DSM programs.  Included inremaining balance of deferred net lost revenue as of April 30, 2014, deferred within regulatory assets resulting from the filing was a petition to update the rate rider to provide for the recovery of costs, lost net revenue, and the approved shared savings incentive for investing in such DSM Programs.

May 2013 order previously described.


Electric - BLRA


In January 2010,May 2011, the SCPSC approved SCE&G’s request for an order pursuant to the BLRA to approve an updated construction and capital cost schedule for the construction of two new nuclear generating units at Summer Station.  The updated schedule provides details of the construction and capital cost schedule beyond what was proposed and included in the original BLRA filing described below.

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

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Table of Contents

In May 2009, two intervenors filed separate appeals of the SCPSC order with the South Carolina Supreme Court. With regard to the first appeal, which challenged the SCPSC’s prudency finding, the South Carolina Supreme Court issued an opinion on April 26, 2010, affirming the decision of the SCPSC. As for the second appeal, the South Carolina Supreme Court reversed the SCPSC’s decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G’s share of the project, as originally approved by the SCPSC, was $4.5 billion in 2007 dollars. Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court’s ruling, however, did not affect the project schedule or disturb the SCPSC’s issuance of a certificate of environmental compatibility and public convenience and necessity, which is required to construct the New Units. On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule sought by SCE&G that, reflected the removal of the contingency reserve andamong other matters, incorporated then identifiablethen-identifiable additional capital costs of $173.9$173.9 million (in (SCE&G's portion in 2007 dollars), and by order dated May 16, 2011,.


In November 2012, the SCPSC approved thean updated construction schedule and additional updated capital costs schedule as outlinedof $278 million (SCE&G's portion in the petition.

On February 29,2007 dollars). The November 2012 SCE&G filed a petition with the SCPSC seeking an order approving a further updated capital cost and construction schedule that incorporatesapproved additional identifiable capital costs of approximately $6$1 million (SCE&G’s&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications.  That petition also includes increased capital costs ofmodifications; approximately $12$8 million (SCE&G’s&G's portion in 2007 dollars) related to transmission infrastructure.  Finally, that petition includes amounts ofinfrastructure; and approximately $137$132 million (SCE&G’s&G's portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. Future petitions would be filedIn addition, the order approved


61



revised substantial completion dates for any costs arising from the resolutionNew Units based on the March 30, 2012 issuance of the commercialCOL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims discussed in Note 1 to the consolidated financial statements (e.g., thosefor costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site).

site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals. For further discussion of new nuclear construction matters, see Note 9.


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&G's updated cost of debt and capital structure and on an allowed return on common equity of 11%11.0%. The SCPSC has approved the following rate changes under the BLRA effective for bills rendered on and after October 30 in the following years:

Year

 

Increase

 

Amount

 

2011

 

2.4

%

$

52.8 million

 

2010

 

2.3

%

$

47.3 million

 

2009

 

1.1

%

$

22.5 million

 

Year Increase Amount
2013 2.90% $67.2 million
2012 2.30% $52.1 million
2011 2.40% $52.8 million
Gas

SCE&G

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

Year

 

Action

 

Amount

 

2011

 

2.1

%

Increase

 

$

8.6 million

 

2010

 

2.1

%

Decrease

 

$

10.4 million

 

2009

 

2.5

%

Increase

 

$

13.0 million

 

Year Action Amount
2013 No change  
2012 2.10% Increase $7.5 million
2011 2.10% Increase $8.6 million
SCE&G’s&G's natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred, including costs related to hedging natural gas purchasing activities.incurred. SCE&G’s&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month12-month rolling average. The annual PGA hearing to review SCE&G’saverage, and its gas purchasing policies and procedures was conducted in November 2011 beforepractices are reviewed annually by the SCPSC. The annual reviews conducted for each of the 12-month periods ended July 31, 2013 and 2012 resulted in the SCPSC issuedissuing an order in January 2012 finding that SCE&G’s&G's gas purchasing policies and practices during theeach review period of August 1, 2010 through July 31, 2011, were reasonable and prudent and authorized the suspension of SCE&G’s natural gas hedging program.

65prudent.




Table of Contents

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 itPSNC Energy to recover, in any manner authorized by the NCUC, losses on negotiated gas and transportation sales.


PSNC Energy’sEnergy's rates are established using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted periodically to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collectionsunder-collection of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’sEnergy'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 January 2012, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy’s rates.  The rate adjustment was effective with the first billing cycle in February 2012.

In December 2011,October 2013, in connection with PSNC Energy’s 2011Energy's 2013 Annual Prudence Review, the NCUC determinedissued an order finding that PSNC Energy’sEnergy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2011.  On February 2, 2012,2013.


During the Public Staffthird quarter of 2013, the State of North Carolina passed legislation that makes changes to statutes covering gross receipts, sales and use, excise, franchise and income taxes.  In the fourth quarter, in response to this legislation, the

62



NCUC initiated a proceeding to investigate how it should proceed in response to the enactment of such legislation.  Because the investigation was not completed before January 1, 2014, the NCUC filed a motion requestingissued an order notifying utilities that the NCUC reconsider and modify its order by reassigning certain charges (totaling approximately $0.4 million) fromincremental revenue requirement impact associated with the change in the level of state income tax expense included in each utility’s cost of gas.  PSNC Energy cannot predict the outcome of this matter, but the Company does not believe it will haveservice would be deemed to be collected on a material effect on the Company’s results of operations, cash flows, or financial condition.

In October 2011, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy’s rates.  The rate adjustment was effective with the first billing cycle in November 2011.  In October 2010, the NCUC approved a 12.5 cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in November 2010. In February 2010, the NCUC approved a ten cent per therm increase in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in March 2010.

provisional basis (subject to refund) beginning January 1, 2014.

Regulatory Assets and Regulatory Liabilities

The Company’sCompany'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. SubstantiallyOther than unrecovered plant, substantially all of our regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.

 

 

December 31,

 

Millions of dollars

 

2011

 

2010

 

Regulatory Assets:

 

 

 

 

 

Accumulated deferred income taxes

 

$

243

 

$

210

 

Under-collections—electric fuel adjustment clause

 

28

 

25

 

Environmental remediation costs

 

30

 

32

 

AROs and related funding

 

316

 

298

 

Franchise agreements

 

40

 

45

 

Deferred employee benefit plan costs

 

392

 

326

 

Planned major maintenance

 

6

 

6

 

Deferred losses on interest rate derivatives

 

154

 

83

 

Deferred pollution control costs

 

25

 

13

 

Other

 

45

 

23

 

Total Regulatory Assets

 

$

1,279

 

$

1,061

 

Regulatory Liabilities:

 

 

 

 

 

Accumulated deferred income taxes

 

$

23

 

$

26

 

Asset removal costs

 

662

 

780

 

Storm damage reserve

 

32

 

38

 

Monetization of bankruptcy claim

 

34

 

37

 

Deferred gains on interest rate derivatives

 

24

 

26

 

Other

 

3

 

6

 

Total Regulatory Liabilities

 

$

778

 

$

913

 

66


  December 31,
Millions of dollars 2013 2012
Regulatory Assets:    
Accumulated deferred income taxes $259
 $254
Under-collections—electric fuel adjustment clause 18
 66
Environmental remediation costs 41
 44
AROs and related funding 368
 319
Franchise agreements 31
 36
Deferred employee benefit plan costs 238
 460
Planned major maintenance 
 6
Deferred losses on interest rate derivatives 124
 151
Deferred pollution control costs 37
 38
Unrecovered plant 145
 20
DSM Programs 51
 27
Other 48
 43
Total Regulatory Assets $1,360
 $1,464

Regulatory Liabilities:    
Accumulated deferred income taxes $24
 $21
Asset removal costs 695
 692
Storm damage reserve 27
 27
Monetization of bankruptcy claim 29
 32
Deferred gains on interest rate derivatives 181
 110
Planned major maintenance 10
 
Total Regulatory Liabilities $966
 $882

Table of Contents

Accumulated deferred income tax liabilities arisingthat 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


Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC during annual hearings which are expected to be recovered in retail electric rates in future periods.  These amounts are expected to be recovered in retail electric rates during the period January 2013 through April 2013.  SCE&G is allowed to recover interest on actual base fuel deferred balances through the recovery period.

over periods exceeding 12 months.


Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by the Company. These regulatory assetsCompany, and are expected to be recovered over periods of up to approximately 2326 years.



63



ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station Unit 1 and conditional AROs.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 9590 years.


Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on ana SCPSC order, SCE&G began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years.


Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. A significant majorityIn connection with the December 2012 rate order, approximately $63 million of these deferred pension costs for electric operations are being recovered through utility rates over approximately 30 years. In connection with the October 2013 RSA order, approximately $14 million of deferred pension costs for gas operations are being recovered through utility rates over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 14 years, although recovery periods could become longer at the election of the SCPSC.

12 years.


Planned major maintenance related to certain fossil fuelfossil-fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders. SCE&G collected $8.5collects $18.4 million annually through July 15, 2010, through electric rates, to offset certain turbine maintenance expenditures. After July 15, 2010, SCE&G began collecting $18.4 million annually for this purpose. Nuclearsuch equipment maintenance. Through December 31, 2012, nuclear refueling charges arewere accrued during each 18-month18-month refueling outage cycle as a component of cost of service.

In connection with the December 2012 rate order, effective January 1, 2013, SCE&G collects and accrues $16.8 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 terminationsettlement of certain interest rate swapsderivatives designated as cash flow hedges. Thesehedges and (ii) the changes in fair value and payments received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years.

The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense 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 installation of scrubbers at Wateree and Williams Stations pursuant to specific regulatory orders. Such costs related to Williams Station amount to $9.4 million at December 31, 2011 and are being recovered through utility rates over approximately 30 years.  The remaining costs relateperiods up to Wateree Station, for which30 years.

Unrecovered plant represents the Company will seek recovery in future proceedings before the SCPSC.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 allowedamortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives, or up to accrue interest onapproximately 14 years. Unamortized amounts are included in rate base and are earning a current return.

DSM Programs represents deferred costs relatedand certain unrecovered lost revenue associated with SCE&G’s Demand Side Management programs.  Deferred costs are currently being recovered over 5 years through a SCPSC approved rider.  Unrecovered lost revenue is to Wateree Station.

be recovered over periods not to exceed 24 months from date of deferral.  See Rate Matters - Electric Base Rates above for details regarding a 2014 filing with the SCPSC regarding recovery of these deferred costs and unrecovered lost revenue.


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

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Table of Contents

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


The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100$100 million, which can be applied to offset incremental storm damage costs in excess of $2.5$2.5 million in a calendar year, certain transmission and distribution insurance premiums and certain tree trimming and vegetation management expenditures in excess of amounts included in base rates.  During the years ended December 31, 2011 and 2010,year. Pursuant to specific regulatory orders, SCE&G applied costs of $6.4 million and $9.5 million, respectively, to the reserve. Pursuant to SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&Ghas suspended collection of the storm damage reserve indefinitely pending future SCPSC action.

collection through rates indefinitely.


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


64



The SCPSC, the NCUC or the FERC havehas 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 thesesuch 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’sCompany's results of operations, liquidity or financial position in the period the write-off would be recorded.


3.COMMON EQUITY

The Company’s articles of incorporation do not limit the dividends that may be paid on its common stock. However, SCANA’s junior subordinated indenture (relating to the Hybrids), SCE&G’s bond indenture (relating to the Bonds) and PSNC Energy’s note purchase and debenture purchase agreements each contain provisions that, under certain circumstances, which the Company considers to be remote, could limit the payment of cash dividends on their respective common stock.

With respect to hydroelectric projects, the

The Federal Power Act requires the appropriation of a portion of certain earnings therefrom.from hydroelectric projects. At December 31, 2011,2013 and 2012, approximately $58.8$63.1 million and $61.0 million of retained earnings, respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.

Cash dividends on SCANA’s common stock were declared during 2011, 20102013, 2012 and 20092011 at an annual rate per share of $2.03, $1.98 and $1.94, $1.90 and $1.88, respectively.

The accumulated balances related to each component of accumulated other comprehensive income (loss), net of tax, were as follows:

Millions of Dollars

 

2011

 

2010

 

Net unrealized losses on cash flow hedging activities, net of taxes of $50 and $22

 

$

(81

)

$

(36

)

Net unrealized deferred costs of employee benefit plans, net of taxes of $8 and $6

 

(13

)

(11

)

Total

 

$

(94

)

$

(47

)

The Company recognized losses of $7.0 million, $12.3 million and $66.9 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the years ended December 31, 2011, 2010 and 2009, respectively.

Millions of Dollars Gains (Losses) on Cash Flow Hedges Deferred Employee Benefit Plans Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Loss as of January 1, 2012 $(81) $(13) $(94)
    Other comprehensive income (loss) 11
 (3) 8
Accumulated Other Comprehensive Loss as of December 31, 2012 (70) (16) (86)
    Other comprehensive income 18
 8
 26
Accumulated Other Comprehensive Loss as of December 31, 2013 $(52) $(8) $(60)
Authorized shares of common stock were 200 million as of December 31, 20112013 and 150 million as of December 31, 2010.

2012.

SCANA issued common stock valued at $97.8$100.9 million $91.1, $97.7 million and $91.1$97.8 million (when issued) during the years ended December 31, 2011, 20102013, 2012 and 2009,2011, respectively, which was satisfied using original issue shares, through various compensation and dividend reinvestment plans, including the Stock Purchase Savings Plan.


68In March 2013, SCANA settled all forward sales contracts related to its common stock through the issuance of approximately 6.6 million common shares, resulting in net proceeds of approximately $196.2 million.



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Table of Contents

SCANA issued common stock valued at $59.2 million (at time of issue) in a public offering on May 17, 2010 and entered into forward agreements for the sale of approximately 6.6 million shares.  The forward agreements, after being extended by amendment dated October 26, 2011, are to be settled no later than December 31, 2012.  SCANA intends to use the net proceeds to finance capital expenditures, including the construction of the New Units, and for general corporate purposes, including repayment of indebtedness incurred for such purposes.

On January 7, 2009, SCANA issued common stock valued at $102.1 million (at time of issue).  Net proceeds were used to finance capital expenditures, including the construction of new nuclear units, and for general corporate purposes.


4.LONG-TERM AND SHORT-TERM DEBT

Long-term debt by type with related weighted average interest rates and maturities at December 31 is as follows:

 

 

 

 

2011

 

2010

 

Dollars in millions

 

Maturity

 

Balance

 

Rate

 

Balance

 

Rate

 

Medium-Term Notes (unsecured)(a)

 

2012 - 2021

 

$

800

 

5.69

%

$

950

 

6.51

%

Senior Notes (unsecured)(b)

 

2034

 

101

 

6.47

%

106

 

6.47

%

First Mortgage Bonds (secured)

 

2013 - 2041

 

2,790

 

5.89

%

2,560

 

6.03

%

Junior Subordinated Notes (unsecured)(c)

 

2065

 

150

 

7.70

%

150

 

7.70

%

GENCO Notes (secured)

 

2012 - 2024

 

247

 

5.86

%

262

 

5.91

%

Industrial and Pollution Control Bonds(d)

 

2012 - 2038

 

194

 

4.48

%

228

 

4.63

%

Senior Debentures(e)

 

2012 - 2026

 

353

 

5.92

%

206

 

6.94

%

Fair Value of Interest Rate Swaps

 

 

 

 

 

 

5

 

 

 

Other

 

2012 - 2027

 

31

 

 

 

36

 

 

 

Total debt

 

 

 

4,666

 

 

 

4,503

 

 

 

Current maturities of long-term debt

 

 

 

(31

)

 

 

(337

)

 

 

Unamortized discount

 

 

 

(13

)

 

 

(14

)

 

 

Total long-term debt, net

 

 

 

$

4,622

 

 

 

$

4,152

 

 

 


    2013 2012
Dollars in millions Maturity Balance Rate Balance Rate
Medium Term Notes (unsecured) 2020 - 2022 $800
 5.42% $800
 5.02%
Senior Notes (unsecured) (a) 2034 92
 0.94% 96
 1.01%
First Mortgage Bonds (secured) 2018 - 2042 3,540
 5.60% 3,290
 5.66%
Junior Subordinated Notes (unsecured) (b) 2065 150
 7.92% 150
 7.70%
GENCO Notes (secured) 2018 - 2024 233
 5.89% 240
 5.87%
Industrial and Pollution Control Bonds (c) 2014 - 2038 158
 3.83% 161
 4.32%
Senior Debentures 2020- 2026 350
 5.93% 350
 5.90%
Nuclear Fuel Financing 2016 100
 0.78% 
 
Other 2014 - 2027 20
 2.73% 27
 2.39%
Total debt   5,443
   5,114
  
Current maturities of long-term debt   (54)   (172)  
Unamortized premium (discount)   6
   7
  
Total long-term debt, net   $5,395
   $4,949
  
(a)Includes fixed rate debt hedged by variable interest rate swaps of $250 million in 2011 and $550 million in 2010.

(b)Variable rate notes hedged by a fixed interest rate swap.swap (fixed rate of

(c)6.47%)

(b)  May be extended through 2080.

2080

(d)(c) Includes variable rate debt of $67.8 million at December 31, 2013 (rate of 0.11%) and 2012 (rate of 0.17%) which are hedged by fixed rate swaps of $71.4 million in 2011 and 2010.swaps.

(e)Includes fixed rate debt hedged by a variable interest rate swap of $3.2 million in 2011 and $6.4 million in 2010.


The annual amounts of long-term debt maturities for the years 20122014 through 20162018 are summarized as follows:

Year

 

Millions
of dollars

 

2012

 

$

280

 

2013

 

171

 

2014

 

52

 

2015

 

13

 

2016

 

12

 

Year 
Millions
of dollars
2014 $54
2015 15
2016 114
2017 13
2018 722
In June 2013, SCE&G issued $400 million of 4.60% first mortgage bonds due June 15, 2043. Proceeds from this sale were used to pay at maturity $150 million of its 7.125% first mortgage bonds due June 15, 2013, to repay short-term debt primarily incurred as a result of SCE&G's construction program, to finance capital expenditures, and for general corporate purposes.

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

In January 2013, JEDA issued for the benefit of SCE&G $39.5 million of 4.0% tax-exempt industrial revenue bonds due February 1, 2028, and $14.7 million of 3.63% tax-exempt industrial revenue bonds due February 1, 2033. Proceeds from these sales were loaned by JEDA to SCE&G and, together with other available funds, were used to redeem prior to maturity $56.9 million of 5.2% industrial revenue bonds due November 1, 2027. The borrowings refinanced by these 2013 issuances are classified within Long-term Debt, Net in the consolidated balance sheet.
In July 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042, which constituted a reopening of the prior offering of $250 million of 4.35% first mortgage bonds issued in January 2012. Proceeds from these sales 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.

66




In January 2012, SCANA issued $250$250 million of 4.125% medium term notes due February 1, 2022. Proceeds from the sale were used to retire SCANA’s $250SCANA's $250 million of 6.25% medium term notes due February 1, 2012.  The borrowings refinanced by this 2012 issuance are classified within Long-term Debt, Net in the consolidated balance sheet.

In January 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042.  Proceeds from the sale were used to repay short-term debt primarily incurred as a result of our construction program, to finance capital expenditures and for general corporate purposes.


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

SCE&G is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its first mortgage bonds (Bonds) have been issued. Bonds may be issued under the Mortgage in compliancean aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, other than certain Bonds issued on the basis of retired Bonds, may be issued under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice (2.0) the annual interest requirements on all debt covenants.

outstanding Bonds and Bonds to be outstanding (Bond Ratio). For the year ended December 31, 2013, the Bond Ratio was 695.28

.



Table of Contents

Lines of Credit and Short-Term Borrowings

At December 31, 20112013 and 2010,2012, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:

 

 

SCANA

 

SCE&G

 

PSNC Energy

 

Millions of dollars

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Lines of Credit:

 

 

 

 

 

 

 

 

 

 

 

 

 

Committed long-term

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

300

 

$

300

 

$

1,100

 

$

1,100

 

$

100

 

$

100

 

LOC advances

 

 

 

 

 

 

 

Weighted average interest rate

 

 

 

 

 

 

 

Outstanding commercial paper (270 or fewer days)

 

$

131

 

$

39

 

$

512

 

$

381

 

$

10

 

 

Weighted average interest rate

 

.63

%

.35

%

.56

%

.42

%

.57

%

 

Letters of credit supported by LOC

 

$

3

 

$

3

 

$

.3

 

$

.3

 

 

 

Available

 

$

166

 

$

258

 

$

588

 

$

719

 

$

90

 

$

100

 

  SCANA SCE&G PSNC Energy
Millions of dollars 2013 2012 2013 2012 2013 2012
Lines of Credit:    
    
    
Total committed long-term $300
 $300
 $1,400
 $1,400
 $100
 $100
LOC advances 
 
 
 
 
 
Weighted average interest rate 
 
 
 
 
 
Outstanding commercial paper (270 or fewer days) $125
 $142
 $251
 $449
 
 $32
Weighted average interest rate 0.39% 0.58% 0.27% 0.42% 
 0.44%
Letters of credit supported by LOC $3
 $3
 $0.3
 $0.3
 
 
Available $172
 $155
 $1,149
 $951
 $100
 $68
SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300$300 million $1.1, $1.2 billion (of which $400$500 million relates to Fuel Company) and $100 million, respectively. In addition, SCE&G is party to a three-year credit agreement in the amount of $200 million. In October 2013, the term of each of these credit agreements was extended by one year, such that the five-year agreements expire in October 2018, and $100 million, respectively, which expirethe three-year agreement expires in October 23, 2015.2016. These credit agreements are used for general corporate purposes, including liquidity support for each company’scompany'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.N.A. and Morgan Stanley Bank, N.A. each provide 10%10.7% of the aggregate $1.5$1.8 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch and UBS Loan Finance LLC each provide 8%8.9%, and Deutsche Bank AG New York Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%6.3%ThreeTwo other banks provide the remaining 6%. These bank credit facilities supportsupport. The Company pays fees to the issuancebanks as compensation for maintaining the committed lines of commercial paper by SCANA, SCE&G (including Fuel Company) and PSNC Energy. When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCANA, SCE&G (including Fuel Company) and PSNC Energy.

credit. Such fees were not material in any period presented.

The Company is obligated with respect to an aggregate of $68.3$67.8 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company.  The letters of credit expire, subject to renewal, in the fourth quarter of 2014.

The Company pays fees to the banks as compensation for maintaining committed lines of credit.

Such fees were not material in any period presented.


67



5.INCOME TAXES

Total

Components of income tax expense attributable to income for 2013, 2012 and 2011 2010 and 2009 isare as follows:

Millions of dollars

 

2011

 

2010

 

2009

 

Current taxes:

 

 

 

 

 

 

 

Federal

 

$

52

 

$

(47

)

$

63

 

State

 

10

 

1

 

(6

)

Total current taxes

 

62

 

(46

)

57

 

Deferred taxes, net:

 

 

 

 

 

 

 

Federal

 

122

 

223

 

94

 

State

 

12

 

13

 

8

 

Total deferred taxes

 

134

 

236

 

102

 

Investment tax credits:

 

 

 

 

 

 

 

Deferred-state

 

 

 

20

 

Amortization of amounts deferred-state

 

(25

)

(28

)

(9

)

Amortization of amounts deferred-federal

 

(3

)

(3

)

(3

)

Total investment tax credits

 

(28

)

(31

)

8

 

Total income tax expense

 

$

168

 

$

159

 

$

167

 

70


Millions of dollars 2013 2012 2011
Current taxes:      
Federal $161
 $103
 $52
State 17
 10
 10
Total current taxes 178
 113
 62
Deferred taxes, net:      
Federal 39
 72
 122
State 10
 14
 12
Total deferred taxes 49
 86
 134
Investment tax credits:      
Amortization of amounts deferred-state (1) (14) (25)
Amortization of amounts deferred-federal (3) (3) (3)
Total investment tax credits (4) (17) (28)
Total income tax expense $223
 $182
 $168

Table of Contents

The difference between actual income tax expense and the amount calculated from the application of the statutory 35% federal income tax rate to pre-tax income is reconciled as follows:

Millions of dollars

 

2011

 

2010

 

2009

 

Income

 

$

387

 

$

376

 

$

348

 

Income tax expense

 

168

 

159

 

167

 

Preferred stock dividends

 

 

 

9

 

Total pre-tax income

 

$

555

 

$

535

 

$

524

 

Income taxes on above at statutory federal income tax rate

 

$

194

 

$

187

 

$

183

 

Increases (decreases) attributed to:

 

 

 

 

 

 

 

State income taxes (less federal income tax effect)

 

15

 

9

 

14

 

Amortization of state investment tax credits (less federal income tax effect)

 

(16

)

(18

)

(6

)

Allowance for equity funds used during construction

 

(5

)

(8

)

(10

)

Deductible dividends—Stock Purchase Savings Plan

 

(9

)

(9

)

(8

)

Amortization of federal investment tax credits

 

(3

)

(3

)

(3

)

Domestic production activities deduction

 

(6

)

 

(4

)

Other differences, net

 

(2

)

1

 

1

 

Total income tax expense

 

$

168

 

$

159

 

$

167

 

Millions of dollars 2013 2012 2011
Net income $471
 $420
 $387
Income tax expense 223
 182
 168
Total pre-tax income $694
 $602
 $555
       
Income taxes on above at statutory federal income tax rate $243
 $211
 $194
Increases (decreases) attributed to:      
State income taxes (less federal income tax effect) 22
 19
 15
State investment tax credits (less federal income tax effect) (5) (13) (16)
Allowance for equity funds used during construction (9) (8) (5)
Deductible dividends—Stock Purchase Savings Plan (10) (9) (9)
Amortization of federal investment tax credits (3) (3) (3)
Section 45 tax credits (5) (5) (2)
Domestic production activities deduction (11) (9) (6)
Other differences, net 1
 (1) 
Total income tax expense $223
 $182
 $168

68



The tax effects of significant temporary differences comprising the Company’s net deferred tax liability of $1.5 billion at December 31, 20112013 and $1.4 billion at December 31, 20102012 are as follows:

Millions of dollars

 

2011

 

2010

 

Deferred tax assets:

 

 

 

 

 

Nondeductible reserves

 

$

99

 

$

103

 

Nuclear decommissioning

 

47

 

45

 

Financial instruments

 

50

 

22

 

Unamortized investment tax credits

 

29

 

41

 

Deferred compensation

 

23

 

25

 

Unbilled revenue

 

19

 

19

 

Monetization of bankruptcy claim

 

13

 

14

 

Other

 

15

 

11

 

Total deferred tax assets

 

$

295

 

$

280

 

Deferred tax liabilities:

 

 

 

 

 

Property, plant and equipment

 

$

1,561

 

$

1,418

 

Pension plan income

 

1

 

23

 

Deferred employee benefit plan costs

 

128

 

106

 

Deferred fuel costs

 

47

 

42

 

Other

 

65

 

61

 

Total deferred tax liabilities

 

1,802

 

1,650

 

Net deferred tax liability

 

$

1,507

 

$

1,370

 

Millions of dollars 2013 2012
Deferred tax assets:    
Nondeductible accruals $84
 $143
Asset retirement obligation, including nuclear decommissioning 220
 214
Financial instruments 32
 43
Unamortized investment tax credits 19
 22
Regulatory liability, net gain on interest rate derivative contracts settlement 27
 
Unbilled revenue 
 14
Monetization of bankruptcy claim 11
 12
Other 13
 15
Total deferred tax assets 406
 463
Deferred tax liabilities:    
Property, plant and equipment $1,765
 $1,718
Deferred employee benefit plan costs 63
 148
Regulatory asset-asset retirement obligation 121
 113
Deferred fuel costs 25
 48
Regulatory asset, unrecovered plant 55
 7
Other 84
 71
Total deferred tax liabilities 2,113
 2,105
Net deferred tax liability $1,707
 $1,642
During the third quarter of 2013, the State of North Carolina passed legislation that lowered the state corporate income tax rate from 6.9% to 6.0% in 2014 and 5.0% in 2015.  In connection with this change in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The change in income tax rates did not and is not expected to have a material impact on the Company’s financial position, results of operations or cash flows. Additionally, during the third quarter of 2013, the IRS issued final regulations regarding the capitalization of certain costs for income tax purposes and re-proposed certain other related regulations (collectively referred to as tangible personal property regulations). Related IRS revenue procedures were then issued on January 24, 2014. These regulations did not and are not expected to, have a material impact on the Company's financial position, results of operations or cash flows.
The Company files a consolidated federal income tax return, and the Company and its subsidiaries file various applicable state and local income tax returns. The IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2007 are closed for additional assessment. With few exceptions, the Company is no longer subject to state and local income tax examinations by tax authorities for years before 2008.

In the first quarter of 2010, in connection with a fuel cost recovery settlement (see Note 2), SCE&G accelerated the recognition of certain previously deferred state income tax credits. In the second quarter of 2010, the Company revised (reduced) its estimate of the benefit to be realized from the domestic production activities deduction as a result of a change in method of accounting for certain repairs for tax purposes. In the third quarter of 2010, in connection with the adoption of new retail electric base rates, and pursuant to an SCPSC order, SCE&G accelerated the recognition of additional previously deferred state income tax credits (see Note 2) and also adopted the flow through method of accounting for current and future state tax credits.

71

2009.


Table of Contents

Changes to Unrecognized Tax Benefits

Millions of dollars

 

2011

 

2010

 

Unrecognized tax benefits, January 1

 

$

36

 

 

Gross increases—tax positions in prior period

 

5

 

 

Gross decreases—tax positions in prior period

 

(8

)

 

Gross increases—current period tax positions

 

5

 

$

36

 

Settlements

 

 

 

Lapse of statute of limitations

 

 

 

Unrecognized tax benefits, December 31

 

$

38

 

$

36

 

Millions of dollars 2013 2012 2011
Unrecognized tax benefits, January 1 
 $38
 $36
Gross increases—uncertain tax positions in prior period 
 
 5
Gross decreases—uncertain tax positions in prior period 
 (38) (8)
Gross increases—current period uncertain tax positions $3
 
 5
Settlements 
 
 
Lapse of statute of limitations 
 
 
Unrecognized tax benefits, December 31 $3
 $
 $38

In connection with the change in method of tax accounting for certain repair costs for tax purposes referred to above,in prior years, the Company identified approximately $38 million ofhad previously recorded an unrecognized tax benefit. BecauseDuring the first quarter of 2012, the publication of new administrative

69



guidance from the IRS allowed the Company to recognize this methodbenefit. Since this change iswas primarily a temporary difference, the recognition of this additional benefit if recognized, woulddid not have a significant effect on the Company's effective tax rate.

During 2013, the Company amended certain of its tax returns to claim certain tax-defined research and development deductions and credits. In connection with these filings, the Company recorded an unrecognized tax benefit of $3 million. If recognized, this tax benefit would affect the Company’s effective tax rate. By December 31, 2012, itIt is reasonably possible that this unrecognized tax benefit couldwill increase by as much as $12an additional $5 million or decrease by as much as $38 million. The events that could cause thesewithin the next 12 months. No other material changes are direct settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities, orin the lapsestatus of an applicable statute of limitation.

the Company’s tax positions have occurred through December 31, 2013.

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. TheIn connection with the resolution of the uncertainty and recognition of the tax benefit in 2012, during 2012 the Company has not accrued any significant amount of interest expense related to unrecognized tax benefits or tax penalties in 2010 or 2009.  The Company has accruedreversed $2 million of interest expense related to unrecognizedwhich had been accrued during 2011. The Company has not recorded interest expense or penalties associated with the 2013 uncertain tax benefits in 2011.

position.


6.DERIVATIVE FINANCIAL INSTRUMENTS

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

Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by the Company. SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries. The Risk Management Committee, which is comprised of certain officers, including the Company’s Risk Management Officer and senior officers, apprises the Audit Committee of the Board of Directors with regard to the management of risk and brings to the Board’sAudit Committee's attention anysignificant 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 settlementsettlements of commodity derivatives are classified as an operating activityactivities in the consolidated statement of cash flows.

The Company’s regulated gas operations (SCE&G and

PSNC Energy) hedgeEnergy hedges natural gas purchasing activities using over-the-counter options and swaps and NYMEX futures and options. SCE&G’s tariffs include a PGA that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCE&G’s hedging activities are to be included in the PGA. As such, the cost of derivatives and gains and losses on such derivatives utilized to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. PSNC Energy’s tariffs also include a provision for the recovery of actual gas costs incurred.incurred, including any costs of hedging. PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or

72



Table of Contents

losses from its hedging program in deferred accounts as a regulatory asset or liability for the over- or under-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes.

The unrealized

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


70



Interest Rate Swaps

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

The Company uses swaps to synthetically convert fixed rate debt to variable rate debt. These swaps are designated as fair value hedges. Periodic payments to or receipts from swap counterparties are recorded within interest expense and are classified as an operating activityIn cases in which the condensed consolidated statements of cash flows. In addition, gains on certain swaps that were terminated prior to maturity of the underlying debt instruments are being amortized to interest expense over the life of the debt they hedged.

The Company synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges. Periodichedges, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense and are classified as an operating activity for cash flow purposes.

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. TheExcept 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, and forliabilities. For the holding company or nonregulated subsidiaries, such amounts are recorded in other comprehensive income.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 issued in 2013, interest rate derivatives entered into by SCE&G after October 2013 are no longer designated as cash flow hedges, and fair value changes and settlement amounts are recorded as regulatory assets and liabilities. Upon settlement, losses on swaps will be amortized over the lives of related debt issuances, and gains may be applied to under-collected fuel, be amortized to interest expense or applied as otherwise directed by the SCPSC. As discussed in Note 2, in these orders, the SCPSC directed SCE&G to recognize $41.6 million and $8.5 million of realized gains (which had been deferred in regulatory liabilities) within other income, fully offsetting revenue reductions related to under-collected fuel balances and under-collected amounts arising under the eWNA program which was terminated at the end of 2013.

Cash payments made or received upon terminationsettlement of these financial instruments are classified as an investing activity in the consolidated statements ofactivities for cash flows.

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 DT)

 

Hedge designation

 

Gas
Distribution

 

Retail Gas
Marketing

 

Energy
Marketing

 

Total

 

As of December 31, 2011

 

 

 

 

 

 

 

 

 

Cash flow

 

 

6,566,000

 

29,861,763

 

36,427,763

 

Not designated(a)

 

9,080,000

 

 

31,943,563

 

41,023,563

 

Total(a)

 

9,080,000

 

6,566,000

 

61,805,326

 

77,451,326

 

As of December 31, 2010

 

 

 

 

 

 

 

 

 

Cash flow

 

 

5,715,000

 

17,190,351

 

22,905,351

 

Not designated(b)

 

10,677,000

 

 

20,588,581

 

31,265,581

 

Total(b)

 

10,677,000

 

5,715,000

 

37,778,932

 

54,170,932

 


  
Commodity and Other Energy
Management Contracts (in MMBTU)
Hedge designation 
Gas
Distribution
 
Retail Gas
Marketing
 
Energy
Marketing
 Total
As of December 31, 2013  
  
  
  
Commodity 6,070,000
 6,726,000
 2,560,000
 15,356,000
Energy Management (a) 
 
 27,359,958
 27,359,958
Total (a) 6,070,000
 6,726,000
 29,919,958
 42,715,958
As of December 31, 2012  
  
  
  
Commodity 5,170,000
 6,490,000
 4,877,000
 16,537,000
Energy Management (b) 
 
 31,763,275
 31,763,275
Total (b) 5,170,000
 6,490,000
 36,640,275
 48,300,275

(a)Includes an aggregate 9,626,000 DT348,453 MMBTU related to basis swap contracts in Energy Marketing.

(b)Includes an aggregate 6,485,536 DT3,500,000 MMBTU related to basis swap contracts in Retail Gas Marketing and Energy Marketing.


73



Table of Contents

The Company was party to interest rate swaps designated as fair value hedges with aggregate notional amounts of $253.2 million and $556.4 million at December 31, 2011 and 2010, respectively, and was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $822.6$128.8 million at December 31, 2013, and $1.1 billion at December 31, 2012. The Company was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.3 billion and $0.0 million at December 31, 2013 and 2012, respectively.



71



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

 

 

Fair Values of Derivative Instruments

 

 

 

Asset Derivatives

 

Liability Derivatives

 

Millions of
dollars

 

Balance Sheet
Location
(c)

 

Fair
Value

 

Balance Sheet
Location
(c)

 

Fair
Value

 

As of December 31, 2011

 

 

 

 

 

 

 

 

 

Derivatives designated as hedging instruments

 

 

 

 

 

 

 

 

 

Interest rate contracts

 

Prepayments and other

 

$

2

 

Other current liabilities

 

$

55

 

 

 

 

 

 

 

Other deferred credits and other liabilities

 

103

 

Commodity contracts

 

Other current liabilities

 

1

 

Prepayments and other

 

1

 

 

 

 

 

$

3

 

Other current liabilities

 

10

 

 

 

 

 

 

 

Other deferred credits and other liabilities

 

3

 

Total

 

 

 

 

 

 

 

$

172

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2010

 

 

 

 

 

 

 

 

 

Derivatives designated as hedging instruments

 

 

 

 

 

 

 

 

 

Interest rate contracts

 

Prepayments and other

 

$

1

 

Other current liabilities

 

$

57

 

 

 

Other deferred debits and other assets

 

7

 

Other deferred credits and other liabilities

 

25

 

Commodity contracts

 

Other current liabilities

 

1

 

Other current liabilities

 

5

 

 

 

 

 

 

 

Other deferred credits and other liabilities

 

2

 

Total

 

 

 

$

9

 

 

 

$

89

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2011

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments

 

 

 

 

 

 

 

 

 

Energy management contracts

 

Prepayments and other

 

$

17

 

Prepayments and other

 

$

3

 

 

 

Other deferred debits and other assets

 

10

 

Other current liabilities

 

13

 

 

 

 

 

 

 

Other deferred credits and other liabilities

 

9

 

Total

 

 

 

$

27

 

 

 

$

25

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2010

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Prepayments and other

 

$

3

 

 

 

 

 

Energy management contracts

 

Prepayments and other

 

7

 

Prepayments and other

 

$

1

 

 

 

Other deferred debits and other assets

 

2

 

Other current liabilities

 

6

 

 

 

 

 

 

 

Other deferred credits and other liabilities

 

2

 

Total

 

 

 

$

12

 

 

 

$

9

 


(c)Asset derivatives represent unrealized gains to the Company, and liability derivatives represent unrealized losses. In the Company’s consolidated balance sheet, unrealized gain and loss positions on commodity contracts with the same counterparty are reported as either a net asset or liability, and for purposes of the above disclosure they are reported on a gross basis.

74


  Fair Values of Derivative Instruments
  Asset Derivatives Liability Derivatives
Millions of dollars 
Balance Sheet
Location
 
Fair
Value
 
Balance Sheet
Location
 
Fair
Value
As of December 31, 2013    
    
Derivatives designated as hedging instruments    
    
Interest rate contracts     Other current liabilities $5
      Other deferred credits and other liabilities 14
Commodity contracts Prepayments and other $2
    
Total   $2
   $19
         
Derivatives not designated as hedging instruments    
    
Interest rate contracts Prepayments and other $13
 Other current liabilities $1
  Other deferred debits and other assets 19
    
Commodity contracts Prepayments and other 2
    
Energy management contracts Prepayments and other 4
 Other current liabilities 4
  Other deferred debits and other assets 4
 Other deferred credits and other liabilities 4
Total   $42
   $9
         
As of December 31, 2012    
    
Derivatives designated as hedging instruments    
    
Interest rate contracts Prepayments and other $42
 Other current liabilities $70
  Other deferred debits and other assets 31
 Other deferred credits and other liabilities 36
Commodity contracts Prepayments and other 1
 Other current liabilities 4
Total   $74
   $110
        

Derivatives not designated as hedging instruments    
    
Commodity contracts Prepayments and other $1
    
Energy management contracts Prepayments and other 7
 Prepayments and other $1
  Other deferred debits and other assets 6
 Other current liabilities 6
     
 Other deferred debits and other assets 6
Total   $14
   $13


Table of Contents

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


Fair Value Hedges

With regard to the Company’s interest rate swaps designated as fair value hedges, any gains or losses related to the gains on those swaps andor the losses on the hedged fixed rate debt are recognized in current earnings and included inwithin interest expense. These gainsThe Company had no interest rate swaps designated as fair

72



value hedges for any period presented, and losses, combined with the amortization of deferred gains on previously terminated swaps as discussed above, resulted in reductions to interest expense of $5.8 million and $11.5 million for the years ended December 31, 2011 and 2010, respectively.

were not significant during any period presented.


Cash Flow Hedges
Derivatives in Cash Flow Hedging Relationships

Derivatives in Cash Flow Hedging Relationships

 

Gain or (Loss)
Deferred in Regulatory
Accounts

 

Gain or (Loss) Reclassified from
Deferred Accounts into Income
(Effective Portion)

 

Millions of dollars

 

(Effective Portion)

 

Location

 

Amount

 

Year Ended December 31, 2011

 

 

 

 

 

 

 

Interest rate contracts

 

$

(76

)

Interest expense

 

$

(3

)

Year Ended December 31, 2010

 

 

 

 

 

 

 

Interest rate contracts

 

$

(36

)

Interest expense

 

$

(2

)

Year Ended December 31, 2009

 

 

 

 

 

 

 

Interest rate contracts

 

$

42

 

Interest expense

 

$

(3

)

Derivatives in Cash Flow Hedging Relationships

 

Gain or (Loss)
Recognized in OCI, net of tax

 

Gain or (Loss) Reclassified from
Accumulated OCI into Income,
net of tax (Effective Portion)

 

Millions of dollars

 

(Effective Portion)

 

Location

 

Amount

 

Year Ended December 31, 2011

 

 

 

 

 

 

 

Interest rate contracts

 

$

(42

)

Interest expense

 

$

(4

)

Commodity contracts

 

(16

)

Gas purchased for resale

 

(9

)

Total

 

$

(58

)

 

 

$

(13

)

Year Ended December 31, 2010

 

 

 

 

 

 

 

Interest rate contracts

 

$

(24

)

Interest expense

 

$

(4

)

Commodity contracts

 

(12

)

Gas purchased for resale

 

(13

)

Total

 

$

(36

)

 

 

$

(17

)

Year Ended December 31, 2009

 

 

 

 

 

 

 

Interest rate contracts

 

$

9

 

Interest expense

 

$

(3

)

Commodity contracts

 

(39

)

Gas purchased for resale

 

(67

)

Total

 

$

(30

)

 

 

$

(70

)

  
Gain or (Loss)
Deferred in Regulatory
Accounts
 
Loss Reclassified from
Deferred Accounts into Income
(Effective Portion)
Millions of dollars (Effective Portion) Location Amount
Year Ended December 31, 2013  
    
Interest rate contracts $106
 Interest expense $(3)
Year Ended December 31, 2012  
    
Interest rate contracts $84
 Interest expense $(3)
Year Ended December 31, 2011  
    
Interest rate contracts $(76) Interest expense $(3)
  
Gain or (Loss)
Recognized in OCI, net of tax
 
Loss Reclassified from
Accumulated OCI into Income,
net of tax (Effective Portion)
Millions of dollars (Effective Portion) Location Amount
Year Ended December 31, 2013  
    
Interest rate contracts $5
 Interest expense $(8)
Commodity contracts 2
 Gas purchased for resale (3)
Total $7
   $(11)
Year Ended December 31, 2012  
    
Interest rate contracts $(4) Interest expense $(6)
Commodity contracts (4) Gas purchased for resale (13)
Total $(8)   $(19)
Year Ended December 31, 2011  
    
Interest rate contracts $(42) Interest expense $(4)
Commodity contracts (16) Gas purchased for resale (9)
Total $(58)   $(13)
As of December 31, 2011,2013, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive loss to earnings arising from cash flow hedges will include approximately $6.7$1.0 million net of tax as an increase to gas cost and approximately $4.3$7.0 million net of tax as an increase to interest expense, assuming natural gas and financial markets remain at their current levels. As of December 31, 2011,2013, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2016.

Derivatives Not Designated as Hedging Instruments

 

Gain or (Loss) Recognized in Income

 

Millions of dollars

 

Location

 

Amount

 

Year Ended December 31, 2011

 

 

 

 

 

Commodity contracts

 

Gas purchased for resale

 

$

(2

)

Year Ended December 31, 2010

 

 

 

 

 

Commodity contracts

 

Gas purchased for resale

 

(3

)

Year Ended December 31, 2009

 

 

 

 

 

Commodity contracts

 

Gas purchased for resale

 

(16

)

Hedge Ineffectiveness

Other gains (losses)losses recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were $(1.1)insignificant in 2013 and 2012 and were $(1.1) million, net of tax, in 2011 and were insignificant in 2010.2011. These amounts are recorded within interest expense on the statementconsolidated statements of income.

75


Derivatives Not Designated as Hedging Instruments
  Loss Recognized in Income Year Ended December 31,
Millions of dollars Location 2013 2012 2011
Commodity contracts Gas purchased for resale 
 $(1) $(2)


73




The gains reclassified to other income of Contents

$50 million offset revenue reductions as previously described herein and in Note 2.


Credit Risk Considerations

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

Certain of the Company’s derivative instruments contain contingent provisions that require the Company to provide collateral upon the occurrence of specific events, primarily credit rating downgrades. As of December 31, 20112013 and 2010,2012, the Company hashad posted $140.3$26.8 million and $20.0$78.3 million, respectively, of collateral related to derivatives with contingent provisions that arewere in a net liability position. Collateral related to the positions expected to close in the next 12 months is recorded in Prepayments and other on the consolidated balance sheets. Collateral related to the noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments werehad been fully triggered as of December 31, 20112013 and 2010,2012, the Company would behave been required to post an additional $50.7$0.0 million and $74.0$26.2 million, respectively, of collateral to its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of December 31, 20112013 and 2010,2012, are $191.0$25.2 million and $94.0$104.5 million, respectively.


In addition, as of December 31, 2013 and December 31, 2012, the Company has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments had been fully triggered as of December 31, 2013 and December 31, 2012, the Company could request $34.1 million and $32.1 million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of December 31, 2013 and December 31, 2012 is $34.1 million and $32.1 million, respectively. In addition, at December 31, 2013, the Company could have called on letters of credit in the amount of $6 million related to $6 million in commodity derivatives that are in a net asset position, compared to letters of credit of $10 million related to derivatives of $13 million at December 31, 2012, if all the contingent features underlying these instruments had been fully triggered.


74



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

       Gross Amounts Not Offset in the Statement of Financial Position  
Millions of dollarsGross Amounts of Recognized Assets Gross Amounts Offset in the Statement of Financial Position Net Amounts Presented in the Statement of Financial Position Financial Instruments Cash Collateral Received Net Amount
As of December 31, 2013           
Interest rate$32
 
 $32
 $(1) 
 $31
Commodity4
 
 4
 
 
 4
Energy Management8
 
 8
 
 
 8
   Total$44
 
 $44
 $(1) 
 $43
            
Balance sheet locationPrepayments and other $21
      
 Other deferred debits and other assets 23
      
 Total   $44
      
            
As of December 31, 2012           
Interest rate$73
 
 $73
 $(17) 
 $56
Commodity2
 
 2
 
 
 2
Energy Management13
 $(1) 12
 
 
 12
   Total$88
 $(1) $87
 $(17) 
 $70
            
Balance sheet locationPrepayments and other $50
      
 Other deferred debits and other assets 37
      
 Total   $87
      

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

       Gross Amounts Not Offset in the Statement of Financial Position  
Millions of dollarsGross Amounts of Recognized Liabilities Gross Amounts Offset in the Statement of Financial Position Net Amounts Presented in the Statement of Financial Position Financial Instruments Cash Collateral Posted Net Amount
As of December 31, 2013           
Interest rate$20
 
 $20
 $(1) $19
 
Energy Management8
 
 8
 
 6
 $2
   Total$28
 
 $28
 $(1) $25
 $2
            
Balance sheet locationOther current liabilities $10
      
 Other deferred credits and other liabilities 18
      
 Total   $28
      

75



       Gross Amounts Not Offset in the Statement of Financial Position  
Millions of dollarsGross Amounts of Recognized Liabilities Gross Amounts Offset in the Statement of Financial Position Net Amounts Presented in the Statement of Financial Position Financial Instruments Cash Collateral Posted Net Amount
As of December 31, 2012           
Interest rate$106
 
 $106
 $(17) $67
 $22
Commodity4
 
 4
 
 
 4
Energy Management13
 $(1) 12
 
 11
 1
   Total$123
 $(1) $122
 $(17) $78
 $27
            
Balance sheet locationOther current liabilities $80
      
 Other deferred credits and other liabilities 42
      
 Total   $122
      


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 hierarchy in which the measurements fall, were as follows:

 

 

Fair Value Measurements Using

 

Millions of dollars

 

Quoted Prices in Active
Markets for Identical Assets
(Level 1)

 

Significant Other
Observable Inputs
(Level 2)

 

As of December 31, 2011

 

 

 

 

 

Assets-Available for sale securities

 

$

3

 

 

Interest rate contracts

 

 

$

2

 

Commodity contracts

 

 

1

 

Energy management contracts

 

 

27

 

Liabilities-Interest rate contracts

 

 

158

 

Commodity contracts

 

1

 

13

 

Energy management contracts

 

 

26

 

As of December 31, 2010

 

 

 

 

 

Assets-Available for sale securities

 

$

3

 

 

Interest rate contracts

 

 

$

8

 

Commodity contracts

 

2

 

2

 

Energy management contracts

 

 

9

 

Liabilities-Interest rate contracts

 

 

82

 

Commodity contracts

 

1

 

6

 

Energy management contracts

 

 

11

 

 As of December 31, 2013 As of December 31, 2012
Millions of dollarsLevel 1 Level 2 Level 1 Level 2
Assets:       
  Available for sale securities$9
 
 $6
 
  Interest rate contracts
 $32
 
 $73
  Commodity contracts2
 2
 1
 1
  Energy management contracts1
 7
 
 13
Liabilities:       
  Interest rate contracts
 20
 
 106
  Commodity contracts
 
 
 4
  Energy management contracts
 12
 1
 15
There were no Level 3 fair value measurements based on significant unobservable inputs (Level 3) for either period presented. In addition,presented, and there were no transfers of fair value amounts into or out of Levels 1, and 2 or 3 during any periodthe periods presented.

Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 20112013 and December 31, 20102012 were as follows:

 

 

December 31, 2011

 

December 31, 2010

 

Millions of dollars

 

Carrying
Amount

 

Estimated
Fair
Value

 

Carrying
Amount

 

Estimated
Fair
Value

 

Long-term debt

 

$

4,653.0

 

$

5,479.2

 

$

4,488.3

 

$

4,840.5

 

  As of December 31, 2013 As of December 31, 2012
Millions of dollars 
Carrying
Amount
 
Estimated
Fair Value
 
Carrying
Amount
 
Estimated
Fair Value
Long-term debt $5,449.3
 $5,916.3
 $5,121.0
 $6,115.0
Fair values of long-term debt are based on quoted market prices of the instruments or similar instruments. For debt instruments for which no quoted market prices are available, fair values are based on net present value calculations. Carrying values reflectcalculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest

76



rates. As such, the aggregate fair values of interest rate swaps based on discounted cash flow models with independently sourced data.presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent.

76


Carrying values of short-term borrowings approximate their fair values, which are based on quoted prices from dealers in the commercial paper market. These fair values are considered to be Level 2.




Table of Contents

8.             EMPLOYEE BENEFIT PLANS

AND EQUITY COMPENSATION PLAN

Pension and Other Postretirement Benefit Plans

The Company sponsors a noncontributory defined benefit pension plan covering substantially all regular, full-time employees.employees hired before January 1, 2014. In the third quarter of 2013, the Company amended its pension plan such that benefits are no longer offered to employees hired or rehired after December 31, 2013, and pension benefits for existing participants will no longer accrue for services performed or compensation earned after December 31, 2023. The Company’s policy has been to fund the plan to the extentas permitted by applicable federal income tax regulations, as determined by an independent actuary.

The Company’s pension plan provides benefits under a cash balance formula for employees hired before January 1, 2000 who elected that option and for all employees hired on or afterfrom January 1, 2000.2000 through December 31, 2013. Under the cash balance formula, benefits accumulate as a result of compensation credits and interest credits. Employees hired before January 1, 2000 who elected to remain under the final average pay formula earn benefits based on years of credited service and the employee’s average annual base earnings received during the last three years of employment.

Benefits under the cash balance formula and the final average pay formula will continue to accrue through December 31, 2023, after which date no benefits will be accrued except that participants under the cash balance formula will continue to earn interest credits.

In addition to pension benefits, the Company provides certain unfunded postretirement health care and life insurance benefits to certain active and retired employees. Retirees hired before January 1, 2011 share in a portion of their medical care cost. Employees hired after December 31, 2010 are responsible for the full cost of retiree medical benefits elected by them. The Company provides life insurance benefits to retirees at no charge.charge, except that employees hired after December 31, 2010 are ineligible for retiree life insurance benefits. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits.


Changes in Benefit Obligations

The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for retirementpension benefits and the accumulated benefit obligation for other postretirement benefits are presented below.

 

 

Pension
Benefits

 

Other
Postretirement
Benefits

 

Millions of dollars

 

2011

 

2010

 

2011

 

2010

 

Benefit obligation, January 1

 

$

811.8

 

$

789.4

 

$

213.5

 

$

210.4

 

Service cost

 

18.3

 

17.9

 

4.3

 

4.2

 

Interest cost

 

43.5

 

44.0

 

12.2

 

11.9

 

Plan participants’ contributions

 

 

 

3.2

 

3.1

 

Actuarial (gain) loss

 

0.4

 

(1.1

)

7.2

 

(1.6

)

Benefits paid

 

(43.9

)

(38.4

)

(14.3

)

(14.5

)

Benefit obligation, December 31

 

$

830.1

 

$

811.8

 

$

226.1

 

$

213.5

 

  Pension Benefits Other Postretirement Benefits
Millions of dollars 2013 2012 2013 2012
Benefit obligation, January 1 $931.6
 $830.1
 $265.3
 $226.1
Service cost 21.8
 19.6
 5.9
 4.8
Interest cost 38.5
 43.0
 11.1
 11.9
Plan participants’ contributions 
 
 2.6
 2.9
Actuarial (gain) loss (83.4) 96.5
 (35.1) 33.4
Benefits paid (60.0) (57.6) (11.8) (13.8)
Curtailment (25.5) 
 
 
Benefit obligation, December 31 $823.0
 $931.6
 $238.0
 $265.3
The accumulated benefit obligation for retirementpension benefits was $784.9$796.4 million at the end of 20112013 and $766.0$874.6 million at the end of 2010.2012. The accumulated retirementpension benefit obligation differs from the projected retirementpension benefit obligation above in that it reflects no assumptions about future compensation levels.


77



Significant assumptions used to determine the above benefit obligations are as follows:

 

 

Pension
Benefits

 

Other
Postretirement
Benefits

 

 

 

2011

 

2010

 

2011

 

2010

 

Annual discount rate used to determine benefit obligation

 

5.25

%

5.56

%

5.35

%

5.72

%

Assumed annual rate of future salary increases for projected benefit obligation

 

4.00

%

4.00

%

4.00

%

4.00

%

An 8.2%

 Pension Benefits Other Postretirement Benefits
 2013 2012 2013 2012
Annual discount rate used to determine benefit obligation5.03% 4.10% 5.19% 4.19%
Assumed annual rate of future salary increases for projected benefit obligation3.00% 3.75% 3.75% 3.75%
A 7.4% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012.2013. The rate was assumed to decrease gradually to 5.0% for 2020 and to remain at that level thereafter.

A one percent increase in the assumed health care cost trend rate would increase the postretirement benefit obligation at December 31, 20112013 by $1.7$1.3 million and at December 31, 20102012 by $1.8$1.7 million. A one percent decrease in the assumed health care cost trend rate would decrease the postretirement benefit obligation at December 31, 20112013 by $1.5$1.2 million and at December 31, 20102012 by $1.6$1.5 million.

77




Table of Contents

Funded Status

Millions of Dollars

 

Pension
Benefits

 

Other
Postretirement
Benefits

 

December 31,

 

2011

 

2010

 

2011

 

2010

 

Fair value of plan assets

 

$

755.0

 

$

817.2

 

 

 

Benefit obligations

 

830.1

 

811.8

 

$

226.1

 

$

213.5

 

Funded status - asset (liability)

 

$

(75.1

)

$

5.4

 

$

(226.1

)

$

(213.5

)

Millions of Dollars Pension Benefits Other Postretirement Benefits
December 31, 2013 2012 2013 2012
Fair value of plan assets $870.0
 $799.1
 
 
Benefit obligation 823.0
 931.6
 $238.0
 $265.3
Funded status $47.0
 $(132.5) $(238.0) $(265.3)
Amounts recognized on the consolidated balance sheets consist of:

Millions of Dollars

 

Pension
Benefits

 

Other
Postretirement
Benefits

 

December 31,

 

2011

 

2010

 

2011

 

2010

 

Noncurrent asset

 

 

$

5.4

 

 

 

Current liability

 

 

 

$

(10.5

)

$

(11.4

)

Noncurrent liability

 

$

(75.1

)

 

(215.6

)

(202.1

)

Millions of Dollars Pension Benefits Other Postretirement Benefits
December 31, 2013 2012 2013 2012
Current liability 
 
 $(11.5) $(11.0)
Noncurrent asset $47.0
 
 
 
Noncurrent liability 
 $(132.5) (226.5) (254.3)
Amounts recognized in accumulated other comprehensive incomeloss (a component of common equity) as of December 31, 20112013 and 20102012 were as follows:

Millions of Dollars

 

Pension
Benefits

 

Other
Postretirement
Benefits

 

December 31,

 

2011

 

2010

 

2011

 

2010

 

Net actuarial loss

 

$

9.6

 

$

7.1

 

$

1.7

 

$

1.3

 

Prior service cost

 

1.2

 

1.4

 

0.1

 

0.2

 

Transition obligation

 

 

 

0.2

 

0.3

 

Total

 

$

10.8

 

$

8.5

 

$

2.0

 

$

1.8

 

Millions of Dollars Pension Benefits Other Postretirement Benefits
December 31, 2013 2012 2013 2012
Net actuarial loss $5.2
 $10.7
 $1.7
 $3.7
Prior service cost 0.5
 1.0
 0.1
 0.1
Transition obligation 
 
 
 0.1
Total $5.7
 $11.7
 $1.8
 $3.9

Amounts recognized in regulatory assets as of December 31, 2013 and 2012 were as follows:
Millions of Dollars Pension Benefits Other Postretirement Benefits
December 31, 2013 2012 2013 2012
Net actuarial loss $124.8
 $297.0
 $24.4
 $57.0
Prior service cost 12.8
 26.9
 0.9
 1.5
Transition obligation 
 
 
 0.2
Total $137.6
 $323.9
 $25.3
 $58.7
In connection with the joint ownership of Summer Station, as of December 31, 20112013 and 2010,2012, the Company recorded within deferred debits $19.7$14.1 million and $13.0$26.8 million, respectively, attributable to Santee Cooper’s portion of shared pension

78



costs. As of December 31, 20112013 and 2010,2012, the Company also recorded within deferred debits $11.4$12.6 million and $10.7$14.7 million, respectively, from Santee Cooper, representing its portion of the unfunded net postretirement benefit obligation.

Changes in Fair Value of Plan Assets

 

 

Pension Benefits

 

Millions of dollars

 

2011

 

2010

 

Fair value of plan assets, January 1

 

$

817.2

 

$

758.9

 

Actual return on plan assets

 

(18.3

)

96.7

 

Benefits paid

 

(43.9

)

(38.4

)

Fair value of plan assets, December 31

 

$

755.0

 

$

817.2

 

  Pension Benefits
Millions of dollars 2013 2012
Fair value of plan assets, January 1 $799.1
 $755.0
Actual return on plan assets 130.9
 101.7
Benefits paid (60.0) (57.6)
Fair value of plan assets, December 31 $870.0
 $799.1
Investment Policies and Strategies

The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the actuarial accrued liability forobligations of the pension plan, (2) maximizing return within reasonableoverseeing the plan's investments in an asset-liability framework that considers the funding surplus (or deficit) between assets and prudent levels ofliabilities, and overall risk in orderassociated with assets as compared to minimize contributions,liabilities, and (3) maintaining sufficient liquidity to meet benefit payment obligations on a timely basis. The pension plan is closed to new entrants effective January 1, 2014, and benefit accruals will cease effective January 1, 2024. In addition, during 2013, the Company adopted a dynamic investment strategy for the management of the pension plan assets. The strategy will lead to a reduction in equities and an increase in long duration fixed income allocations over time with the intention of reducing volatility of funded status and pension costs in connection with the amendments to the plan.

The pension plan operates with several risk and control procedures, including ongoing reviews of liabilities, investment objectives, levels of diversification, investment managers and performance expectations. The total portfolio is constructed and maintained to provide prudent diversification with regard to the concentration of holdings in individual issues, corporations, or industries.

Transactions involving certain types of investments are prohibited. Equity securities heldThese include, except where utilized by a hedge fund manager, any form of private equity; commodities or commodity contracts (except for unleveraged stock or bond index futures and currency futures and options); ownership of real estate in any form other than publicly traded securities; short sales, warrants or margin transactions, or any leveraged investments; and natural resource properties. Investments made for the pension plan during the periods presented did not include SCANA common stock.

78



Tablepurpose of Contents

engaging in speculative trading are also prohibited.


The Company’s pension plan asset allocation at December 31, 20112013 and 20102012 and the target allocation for 20122014 are as follows:

 

 

Percentage of Plan Assets

 

 

 

Target
Allocation

 

At
December 31,

 

Asset Category

 

2012

 

2011

 

2010

 

Equity Securities

 

65

%

65

%

68

%

Debt Securities

 

35

%

35

%

32

%

  Percentage of Plan Assets
  
Target
Allocation
 
At
December 31,
Asset Category 2014 2013 2012
Equity Securities 58% 59% 66%
Fixed Income 33% 32% 25%
Hedge Funds 9% 9% 9%
For 2012,2014, the expected long-term rate of return on assets will be 8.25%8.00%. In developing the expected long-term rate of return assumptions, management evaluates the pension plan’s historical cumulative actual returns over several periods, considers the expected active returns across various asset classes and assumes an asset allocation of 65%58% with equity managers, and 35%33% with fixed income managers and 9% with hedge fund managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate.

Additional rebalancing may occur subject to funded status improvements as part of the dynamic investment policy adopted for 2014.

Fair Value Measurements

Assets held by the pension plan are measured at fair value as described below. Assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 20112013 and 2010,2012, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:

 

 

 

 

Fair Value Measurements at Reporting
Date Using

 

Millions of dollars

 

Total

 

Quoted Market Prices
in Active Market for
Identical
Assets/Liabilities
(Level 1)

 

Significant
Other
Observable
Inputs
(Level 2)

 

Significant
Other
Unobservable
Inputs
(Level 3)

 

December 31, 2011

 

 

 

 

 

 

 

 

 

Common stock

 

$

324

 

$

324

 

 

 

 

 

Preferred stock

 

1

 

1

 

 

 

 

 

Mutual funds

 

183

 

20

 

$

163

 

 

 

Short-term investment vehicles

 

23

 

 

 

23

 

 

 

Government agency securities

 

32

 

 

 

32

 

 

 

Corporate debt securities

 

51

 

 

 

51

 

 

 

Loans secured by mortgages

 

12

 

 

 

12

 

 

 

Municipals

 

4

 

 

 

4

 

 

 

Common collective trusts

 

37

 

 

 

37

 

 

 

Limited partnerships

 

23

 

 

 

23

 

 

 

Multi-strategy hedge funds

 

65

 

 

 

 

 

$

65

 

 

 

$

755

 

$

345

 

$

345

 

$

65

 

 

 

 

 

 

 

 

 

 

 

December 31, 2010

 

 

 

 

 

 

 

 

 

Common stock

 

$

363

 

$

363

 

 

 

 

 

Mutual funds

 

206

 

25

 

$

181

 

 

 

Short-term investment vehicles

 

18

 

 

 

18

 

 

 

Government agency securities

 

51

 

 

 

51

 

 

 

Corporate debt securities

 

51

 

 

 

51

 

 

 

Loans secured by mortgages

 

9

 

 

 

9

 

 

 

Municipals

 

3

 

 

 

3

 

 

 

Common collective trusts

 

45

 

 

 

45

 

 

 

Limited partnerships

 

26

 

1

 

25

 

 

 

Multi-strategy hedge funds

 

45

 

 

 

 

 

$

45

 

 

 

$

817

 

$

389

 

$

383

 

$

45

 


79





Table

  Fair Value Measurements at Reporting Date Using
Millions of dollars Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3
  December 31, 2013 December 31, 2012
Common stock $332
 $332
     $319
 $319
    
Preferred stock 1
 1
     1
 1
    
Mutual funds 305
 20
 $285
   246
 12
 $234
  
Short-term investment vehicles 19
   19
   20
   20
  
US Treasury securities 33
   33
   42
   42
  
Corporate debt securities 53
   53
   56
   56
  
Loans secured by mortgages 12
   12
   11
   11
  
Municipals 4
   4
   4
   4
  
Limited partnerships 35
 1
 34
   30
 1
 29
  
Multi‑strategy hedge funds 76
     $76
 70
     $70
  $870
 $354
 $440
 $76
 $799
 $333
 $396
 $70

There were no transfers of Contents

fair value amounts into or out of Level 1, 2 or 3 during 2013 or 2012.


The Pension Planpension plan values common stock, preferred stock and certain mutual funds, where applicable, using unadjusted quoted prices from a national stock exchange, such as NYSE and NASDAQ, where the securities are actively traded. Other mutual funds, common collective trusts and limited partnerships are valued using the observable prices of the underlying fund assets based on trade data for identical or similar securities or from a national stock exchange for similar assets or broker quotes. Short-term investment vehicles are funds that invest in short-term fixed income instruments and are valued using observable prices of the underlying fund assets based on trade data for identical or similar securities. Government agency securities are valued using quoted market prices or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Corporate debt securities and municipals are valued based on recently executed transactions, using quoted market prices, or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Loans secured by mortgages are valued using observable prices based on trade data for identical or comparable instruments. Hedge funds are investedrepresent investments in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges and do not trade on a daily basis. The valuationfair value of this multi-strategy hedge fund is estimated based on the net asset value of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may impact their fair value. The estimated fair value is the price at which redemptions and subscriptions occur.

 

 

Fair Value
Measurements
Using
Significant
Unobservable
Inputs
(Level 3)

 

Millions of dollars

 

2011

 

2010

 

Beginning Balance

 

$

45

 

$

14

 

Unrealized gains (losses) included in changes in net assets

 

(1

)

2

 

Purchases, issuances, and settlements

 

21

 

29

 

Transfers in or out of Level 3

 

 

 

Ending Balance

 

$

65

 

$

45

 

  
Fair Value Measurements
Level 3
Millions of dollars 2013 2012
Beginning Balance $70
 $65
Unrealized gains included in changes in net assets 6
 5
Purchases, issuances, and settlements 
 
Ending Balance $76

$70
Expected Cash Flows

The total benefits expected to be paid from the pension plan or from the Company’s assets for the other postretirement benefits plan (net of participant contributions), respectively, are as follows:


80



Expected Benefit Payments

 

 

 

 

Other Postretirement Benefits*

 

Millions of dollars

 

Pension
Benefits

 

Excluding Medicare
Subsidy

 

Including Medicare
Subsidy

 

2012

 

$

73.4

 

$

11.1

 

$

10.8

 

2013

 

66.8

 

11.8

 

11.5

 

2014

 

61.8

 

12.6

 

12.3

 

2015

 

63.3

 

13.4

 

13.1

 

2016

 

65.5

 

14.0

 

13.7

 

2017 - 2021

 

315.5

 

78.6

 

77.3

 


*      Net of participant contributions

Millions of dollars Pension Benefits Other Postretirement Benefits
2014 $61.5
 $11.7
2015 61.2
 12.6
2016 63.8
 13.4
2017 65.8
 14.1
2018 66.1
 14.7
2019-2023 338.4
 82.4
Pension Plan Contributions

The pension trust is adequately funded under current regulations. No contributions have been required since 1997, and as a result of closing the plan to new entrants and freezing benefit accruals in the future, the Company does not anticipate making significant contributions to the pension plan until after 2012.

80

for the foreseeable future.



Table of Contents

Net Periodic Benefit Cost (Income)

The Company records net periodic benefit cost (income) utilizing beginning of the year assumptions. Disclosures required for these plans are set forth in the following tables.

Components of Net Periodic Benefit Cost

 

 

Pension Benefits

 

Other
Postretirement Benefits

 

Millions of dollars

 

2011

 

2010

 

2009

 

2011

 

2010

 

2009

 

Service cost

 

$

18.3

 

$

17.9

 

$

15.5

 

$

4.3

 

$

4.2

 

$

3.7

 

Interest cost

 

43.5

 

44.0

 

44.9

 

12.2

 

11.9

 

12.3

 

Expected return on assets

 

(63.7

)

(61.4

)

(50.8

)

n/a

 

n/a

 

n/a

 

Prior service cost amortization

 

7.0

 

7.0

 

7.0

 

1.0

 

1.0

 

1.0

 

Amortization of actuarial losses

 

12.2

 

16.0

 

23.4

 

0.4

 

 

 

Transition amount amortization

 

 

 

 

0.7

 

0.7

 

0.7

 

Net periodic benefit cost

 

$

17.3

 

$

23.5

 

$

40.0

 

$

18.6

 

$

17.8

 

$

17.7

 

In February 2009,

  Pension Benefits Other Postretirement Benefits
Millions of dollars 2013 2012 2011 2013 2012 2011
Service cost $21.8
 $19.6
 $18.3
 $5.9
 $4.8
 $4.3
Interest cost 38.5
 43.0
 43.5
 11.1
 11.9
 12.2
Expected return on assets (61.4) (59.5) (63.7) n/a
 n/a
 n/a
Prior service cost amortization 6.0
 7.0
 7.0
 0.7
 0.9
 1.0
Amortization of actuarial losses 16.9
 18.4
 12.2
 3.3
 1.4
 0.4
Transition obligation amortization 
 
 
 0.3
 0.7
 0.7
Curtailment loss 9.9
 
 
 
 
 
Net periodic benefit cost $31.7
 $28.5
 $17.3
 $21.3
 $19.7
 $18.6
Prior to July 15, 2010, the SCPSC allowed SCE&G was granted accounting orders by the SCPSC which allowed it to mitigate a significant portion of increased pension cost by deferringdefer as a regulatory asset the amount of pension cost above that which wasexceeding amounts included in then current cost of service rates for its retail electric and gas distribution regulated operations. In connection with the SCPSC's July 2010 upon the new retail electric base rates becoming effective,rate order and November 2010 natural gas RSA order, SCE&G began deferring, as a regulatory asset, all pension cost related to its regulated retail electric and gas operations that otherwise would have been charged to expense. In November 2010, uponEffective in January 2013, in connection with the updated gas rates becoming effective under the RSA,December 2012 rate order, SCE&G began deferring, asamortizing previously deferred pension costs related to retail electric operations totaling approximately $63 million over approximately 30 years (see Note 2) and recovering current pension costs related to retail electric operations through a regulatory asset, allrate rider that may be adjusted annually. Similarly, in connection with the October 2013 RSA order, deferred pension cost related to its regulated natural gas operations that otherwise would have been chargedof approximately $14 million is being amortized over approximately 14 years, and effective November 2013, SCE&G is recovering current pension expense related to expense.

gas operations through cost of service rates (see Note 2).


81



Other changes in plan assets and benefit obligations recognized in other comprehensive income (net of tax) were as follows:

 

 

Pension Benefits

 

Other
Postretirement Benefits

 

Millions of dollars

 

2011

 

2010

 

2009

 

2011

 

2010

 

2009

 

Current year actuarial (gain)/loss

 

$

2.9

 

$

(26.4

)

$

(10.4

)

$

0.4

 

$

(0.1

)

$

0.7

 

Amortization of actuarial losses

 

(0.4

)

(2.0

)

(3.7

)

 

 

 

Amortization of prior service cost

 

(0.2

)

(0.1

)

(0.1

)

(0.1

)

 

(0.1

)

Prior service cost OCI adjustment

 

 

0.8

 

 

 

 

 

Amortization of transition obligation

 

 

 

 

(0.1

)

(0.1

)

(0.1)

 

Total recognized in other comprehensive income

 

$

2.3

 

$

(27.7

)

$

(14.2

)

$

0.2

 

$

(0.2

)

$

0.5

 

  Pension Benefits Other Postretirement Benefits
Millions of dollars 2013 2012 2011 2013 2012 2011
Current year actuarial (gain) loss $(5.0) $1.7
 $2.9
 $(1.8) $2.0
 $0.4
Amortization of actuarial losses (0.5) (0.6) (0.4) (0.2) 
 
Amortization of prior service cost (0.2) (0.2) (0.2) 
 
 (0.1)
Prior service cost (credit) (0.3) 
 
 
 
 
Amortization of transition obligation 
 
 
 (0.1) (0.1) (0.1)
Total recognized in other comprehensive income $(6.0) $0.9
 $2.3
 $(2.1) $1.9
 $0.2
Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows:
  Pension Benefits Other Postretirement Benefits
Millions of dollars 2013 2012 2011 2013 2012 2011
Current year actuarial (gain) loss $(157.5) $45.0
 $70.9
 $(29.9) $31.4
 $6.0
Amortization of actuarial losses (14.7) (16.0) (10.6) (2.7) (1.2) (0.3)
Amortization of prior service cost (5.2) (6.4) (6.4) (0.6) (0.8) (0.9)
Prior service cost (credit) (8.9) 
 
 
 
 
Amortization of transition obligation 
 
 
 (0.2) (0.5) (0.5)
Total recognized in regulatory assets $(186.3) $22.6
 $53.9
 $(33.4) $28.9
 $4.3

Significant Assumptions Used in Determining Net Periodic Benefit Cost

 

 

Pension Benefits

 

Other
Postretirement Benefits

 

 

 

2011

 

2010

 

2009

 

2011

 

2010

 

2009

 

Discount rate

 

5.56

%

5.75

%

6.45

%

5.72

%

5.90

%

6.45

%

Expected return on plan assets

 

8.25

%

8.50

%

8.50

%

n/a

 

n/a

 

n/a

 

Rate of compensation increase

 

4.00

%

4.00

%

4.00

%

4.00

%

4.00

%

4.00

%

Health care cost trend rate

 

n/a

 

n/a

 

n/a

 

8.00

%

8.50

%

8.00

%

Ultimate health care cost trend rate

 

n/a

 

n/a

 

n/a

 

5.00

%

5.00

%

5.00

%

Year achieved

 

n/a

 

n/a

 

n/a

 

2017

 

2017

 

2015

 

81


 Pension Benefits Other Postretirement Benefits
 2013 2012 2011 2013 2012 2011
Discount rate4.10%/5.07%
 5.25% 5.56% 4.19% 5.35% 5.72%
Expected return on plan assets8.00% 8.25% 8.25% n/a
 n/a
 n/a
Rate of compensation increase3.75%/3.00%
 4.00% 4.00% 3.75% 4.00% 4.00%
Health care cost trend raten/a
 n/a
 n/a
 7.80% 8.20% 8.00%
Ultimate health care cost trend raten/a
 n/a
 n/a
 5.00% 5.00% 5.00%
Year achievedn/a
 n/a
 n/a
 2020
 2020
 2017

TableNet periodic benefit cost for the period through September 1, 2013 was determined using a 4.10% discount rate, and net periodic benefit cost after that date was determined using a 5.07% discount rate. Similarly, estimated rates of Contents

compensation increase were changed in connection with the September 1, 2013 remeasurement.


The estimated amounts to be amortized from accumulated other comprehensive incomeloss into net periodic benefit cost in 20122014 are as follows:

Millions of Dollars

 

Pension
Benefits

 

Other
Postretirement
Benefits

 

Actuarial loss

 

$

0.6

 

 

Prior service cost

 

0.2

 

$

0.1

 

Transition obligation

 

 

0.1

 

Total

 

$

0.8

 

$

0.2

 

Millions of Dollars Pension Benefits Other Postretirement Benefits
Actuarial loss $0.2
 
Prior service cost 0.1
 
Total $0.3
 


82



The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2014 are as follows:

Millions of Dollars Pension Benefits Other Postretirement Benefits
Actuarial loss $4.3
 $0.4
Prior service cost 3.5
 0.3
Total $7.8
 $0.7

Other postretirement benefit costs are subject to annual per capita limits pursuant to planthe plan's design. As a result, the effect of a one-percent increase or decrease in the assumed health care cost trend rate on total service and interest cost is approximately $100,000.

not significant.

Stock Purchase Savings Plan

The Company also sponsors a defined contribution plan in which eligible employees may participate. Eligible employees may defer up to 25%75% of eligible earnings subject to certain limits and may diversify their investments. Employee deferrals are fully vested and nonforfeitable at all times. The Company provides 100% matching contributions up to 6% of an employee’s eligible earnings. Total matching contributions made to the plan for 2013, 2012 and 2011 2010 and 2009 were $21.8$23.4 million, $20.8$22.3 million and $21.0$21.8 million, respectively, and were made in the form of SCANA common stock.


9.             SHARE-BASED COMPENSATION

The PlanLTECP provides for grants of nonqualified and incentive stock options, stock appreciation rights, restricted stock, performance shares, performance units and restricted stock units to certain key employees and non-employee directors. The PlanLTECP currently authorizes the issuance of up to five million shares of SCANA’s common stock, no more than one million of which may be granted in the form of restricted stock.

Compensation costs related to share-based payment transactions are required to be recognized in the financial statements. With limited exceptions, including those liability awards discussed below, compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award.

Share-based payment awards do not have non-forfeitable rights to dividends or dividend equivalents. To the extent that the awards themselves do not vest, dividends or dividend equivalents which would have been paid on those awards do not vest.

Liability AwardsAward

s

The 2009-2011, 2010-2012,2011-2013, 2012-2014 and 2011-20132013-2015 performance cycles provide for performance measurement and award determination on an annual basis, with payment of awards being deferred until after the end of the three-yearthree -year performance cycle.  In each of the performance cycles, 20% of the performance award was granted in the form of restricted share units, which are liability awards payable in cash and are subject to forfeiture in the event of retirement or termination of employment prior to the end of the cycle, subject to exceptions for death, disability or change in control.  The remaining 80% of the award was madegranted in performance shares. Each performance share has a value that is equal to, and changes with, the value of a share of SCANA common stock, and dividendstock. Dividend equivalents are accrued on the performance shares. Payoutshares and the restricted share units. Payouts of performance share awards wasare determined by SCANA’s performance against pre-determined measures of TSR as compared to a peer group of utilities (weighted 50%) and growth in “GAAP-adjusted net earnings per share from operations” (weighted 50%). Payouts under the 2009-2011 performance cycle were earned for each year that performance goals were met during the three-year cycle.  Awards were designated as target shares of SCANA common stock and were paid in cash at SCANA’s discretion in February 2012.

Compensation cost of all these liability awards is recognized over their respective three-yearthree -year performance periods based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Awards under the 2011-2013 performance cycle were paid in cash at SCANA’s discretion in February 2014. Cash-settled liabilities related to similar prior programsprogram cycles were paid totaling $13.6$12.2 million in 2011, $12.12013, $11.8 million in 2010,2012, and $9.1$13.6 million in 2009.

2011.

Fair value adjustments for performance awards resulted in compensation expense recognized in the statements of income totaling $6.1$8.7 million in 2011, $14.22013, $15.0 million in 20102012 and $7.2$6.1 million in 2009.2011. Fair value adjustments resulted in capitalized compensation costs of $0.9$1.4 million in 2011, $2.42013, $2.7 million in 20102012 and $0.9$0.9 million in 2009.

822011.



83



Table of Contents

Equity Awards

In

No equity awards were made during any period presented, and the 2008-2010 performance cycle, 20%effects of the performance award was granted in the form of restricted (nonvested) shares rather than restricted share units.  A summary of activity related to these nonvested shares follows:

Nonvested Shares

 

Shares

 

Weighted Average
Grant-Date
Fair Value

 

Nonvested at January 1, 2009

 

74,588

 

$

37.33

 

Forfeited

 

(2,399

)

37.33

 

Nonvested at December 31, 2009

 

72,189

 

37.33

 

Vested

 

(72,189

)

37.33

 

Nonvested at December 31, 2010

 

 

 

 

Nonvested shares were granted at a price corresponding to the opening price of SCANA common stockprevious such awards on the dateCompany's results of the grant. As of December 31, 2010 all compensation cost related to nonvested share-based compensation arrangements under the Plan had been recognized.  The Company expensed compensation costs for nonvested shares of $0.7 million in each of 2010operations, cash flows and 2009 and recognized related tax benefits of $0.3 million in each of 2010 and 2009.  The Company capitalized compensation costs of $0.1 million in each of 2010 and 2009.

A summary of activity related to nonqualified stock options follows:

Stock Options

 

Number of
Options

 

Weighted Average
Exercise Price

 

Outstanding-January 1, 2009

 

106,464

 

$

27.44

 

Exercised

 

(2,875

)

27.50

 

Outstanding-December 31, 2009

 

103,589

 

27.44

 

Exercised

 

(53,246

)

27.40

 

Outstanding-December 31, 2010

 

50,343

 

27.49

 

Exercised

 

(40,267

)

27.48

 

Outstanding-December 31, 2011

 

10,076

 

27.52

 

No stock options were granted or forfeited and all options were fully vested during the periods presented.  The options expire ten years after their respective grant dates, and all options currently outstanding will expire in 2012.  At December 31, 2011, all outstanding options were currently exercisable at a price of $27.52, and had a weighted-average remaining contractual life of less than one year.

The exercise of stock options during the periods presented were satisfied using original issue shares.  For the years ended December 31, 2011, 2010 and 2009, cash realized upon the exercise of options and related tax benefitsfinancial position were not significant.


10.          COMMITMENTS AND CONTINGENCIES

Nuclear Insurance

Under Price-Anderson, SCE&G (for itself and on behalf of Santee-Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the company’s nuclear power plant.  Price-Anderson provides funds up to $12.6$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$375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors.  Each reactor licensee is currently liable for up to $117.5$127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5$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 $78.3$84.8 million per incident, but not more than $11.7$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.


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Table of Contents

SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to the nuclear facilitySummer Station Unit 1 for property damage and outage costs up to $2.75 billion.$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 Ownersowners of the New Units up to $500$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 premiums, SCE&G’s portion of the prospectiveretrospective premium assessment would not exceed $37.3 million.

$41.6 million.

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

Environmental


New Nuclear Construction

SCE&G,

on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $5.4 billion for plant and related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC.


SCE&G's current ownership share in the New Units is 55%. Under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units. Under the terms of this agreement SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, will acquire an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and will acquire the final 2% no later than the second anniversary of such commercial operation date. Under the terms of the agreement SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost of the percentage conveyed as of the date of conveyance, which SCE&G estimates will be approximately $500 million for the entire 5% interest. In December 2009,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 would be reflected in a revised rates filing under the BLRA.

The Consortium has experienced delays in the schedule for fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules are a focus area of the Consortium, including sub-modules for module CA20, which is part of the auxiliary building, and CA01, which houses components inside the containment vessel. Modules

84



CA20 and CA01 are considered critical path items for both New Units. All sub-modules for CA20 have been received on site and its fabrication is underway. CA20 is expected to be ready for placement on the nuclear island of the first New Unit in the first quarter of 2014. In addition, the delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow it to be ready for placement on the nuclear island of the first New Unit during the third quarter of 2014. With this schedule, the Consortium continues to indicate that the substantial completion of the first New Unit is expected to be late 2017 or the first quarter of 2018 and that the substantial completion of the second New Unit is expected to be approximately twelve months after that of the first New Unit. The substantial completion dates currently approved by the SCPSC for the first and second New Units are March 15, 2017 and May 15, 2018, respectively. The SCPSC has also approved an 18-month contingency period beyond each of these dates. The preliminary expected new substantial completion dates are within the contingency periods. SCE&G cannot predict with certainty the extent to which the issue with the sub-modules or the delays in the substantial completion of the New Units will result in increased project costs. However, the preliminary estimate of the delay-related costs associated with SCE&G's 55% share of the New Units is approximately $200 million. SCE&G has not accepted responsibility for any of these delay-related costs and expects to have further discussions with the Consortium regarding such responsibility. Additionally, the EPC Contract provides for liquidated damages in the event of a delay in the completion of the New Units, which will also be included in discussions with the Consortium. SCE&G believes its responsibility for any portion of the $200 million estimate should ultimately be substantially less, once all of the relevant factors are considered.

In addition to the above-described project delays, SCE&G is also aware of financial difficulties at a supplier responsible for certain significant components of the project.  The Consortium is monitoring the potential for disruptions in such equipment fabrication and possible responses.   Any disruptions could impact the project's schedule or costs, and such impacts could be material.

The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude.  During the course of activities under the EPC Contract, issues have materialized that impact project budget and schedule. Claims specifically relating to COL delays,
design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock
conditions at the site resulted in assertions of contractual entitlement to recover additional costs to be incurred. The resolution
of these specific claims is discussed in Note 2. SCE&G expects to resolve any disputes that arise in the future, including any which may arise with respect to the delay-related costs discussed above, through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time, will be recoverable through rates.

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 schedule 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 schedules, construction work crew assignments, and other items. The result will be a revised fully integrated construction schedule that will provide detailed and itemized information on individual budget and cost categories, cost estimates at completion for all non-firm and fixed scopes of work, and the timing of specific construction activities and cash flow requirements. SCE&G anticipates that the revised schedule and the cost estimate at completion for all non-firm and fixed scopes of work will be finalized in the third quarter of 2014. SCE&G plans to reevaluate and reschedule its owners cost estimates and cash flow requirements in light of the new schedule.

When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units.  In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation, as well as a request for information related to emergency plant staffing.  These conditions and requirements are responsive to the NRC's Near-Term Task Force report titled “Recommendations for Enhancing Reactor Safety in the 21st Century.”  This report was prepared in the wake of the March 2011 earthquake-generated tsunami, which severely damaged several nuclear generating units and their back-up cooling systems in Japan.  SCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the construction and operation of the New Units, and SCE&G, pursuant to the license condition, prepared and submitted an integrated response plan for the New Units to the NRC in August 2013.  SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New Units.

Subject to a national megawatt capacity limitation, the electricity to be produced by the New Units (advanced nuclear units, as defined) is expected to qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code. Following the pouring of safety-related concrete for each of the New Units’ reactor buildings (March 2013 for the first New

85



Unit and November 2013 for the second New Unit), SCE&G has applied to the IRS for its allocations of such national megawatt capacity limitation. The IRS will forward the applications to the DOE for appropriate certification.

Environmental
SCE&G
As part of the President's Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA issuedwas directed to issue a final finding that atmospheric concentrationsrevised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of GHG endanger public health and welfare within the meaning of Section 202(a) of the CAA.carbon dioxide from newly constructed fossil fuel-fired units. The rule which became effectivefinal 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 final rule, but does not plan to construct new coal-fired units in January 2010, enablesthe near future. The Memorandum also directed the EPA to regulate GHG emissions underissue standards, regulations, or guidelines for existing units by June 1, 2014, to be made final no later than June 1, 2015. The Company also cannot predict when rules will become final for existing units, if at all, or what conditions they may impose on the CAA. The EPA has committed to issue new rules regulating such emissions in 2012.Company, if any. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.


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 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels.  CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide.  SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements.  On July 6, 2011 the EPA issued the CSAPR.  This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. On August 21, 2012, the Court of Appeals vacated CSAPR and left CAIR in place. The EPA's petition for rehearing of the Court of Appeals' order was denied. In June 2013 the U.S. Supreme Court agreed to review the Court of Appeals' decision and oral arguments were held on December 10, 2013. A decision is still pending. Air quality control installations that SCE&G and GENCO have already completed should assisthave allowed the Company in complyingto comply with the reinstated CAIR and will also allow it to comply with CSAPR, and the reinstated CAIR.if reinstated. The Company will continue to pursue strategies to comply with all applicable environmental regulations.  Any costs incurred to comply with such regulations are expected to be recoverable through rates.

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

In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court


The CWA provides for the Districtimposition of Columbia vacatedeffluent limitations that require treatment for wastewater discharges. Under the rule for electric utility steam generating units.  In March 2011, the EPA proposedCWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new standards for mercury and other specified air pollutants.effluent limitations would be incorporated. The rule, which becomes effective on April 16, 2012, provides up to four years for facilities to meet the standards.  The rule is currently being evaluated by the Company. Any costs incurred to comply with this rule or other rules issued by the EPAELG Rule was published in the future areFederal Register on June 7, 2013, and is expected to be recoverable through rates.

SCE&G has been named, along with 53 others, byfinalized May 22, 2014. The EPA expects compliance as soon as possible after July 2017 but no later than July 2020.


Additionally, the EPA asis expected to issue a PRP at the AER Superfund site locatedrule that modifies requirements for existing cooling water intake structures in Augusta, Georgia.early 2014. The PRPs funded a Remedial InvestigationCompany is conducting studies and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that was completed in 2010. A clean-up cost has been estimated and the PRPs have agreedis developing or implementing compliance plans for these initiatives. Congress is expected to an allocation of those costs based primarily on volume and type of material each PRP sentconsider further amendments to the site. SCE&G’s allocation did notCWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones. These provisions, if passed, could have a material impact on itsthe financial condition, results

86



of operations and cash flows of the Company. The Company believes that any additional costs imposed by such regulations would be recoverable through rates.

In response to a federal court order to establish a definite timeline for a CCR rule, the EPA has said it will issue new federal regulations affecting the management and disposal of CCRs, such as ash, by December 2014. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO. While the Company cannot predict how extensive the regulations will be, the Company believes that any additional costs imposed by such regulations would be recoverable through rates.
The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998. The Nuclear Waste Act also imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or financial condition.

84



TableHigh-Level Radioactive Waste with the DOE in 1983. As of Contents

December 31, 2013, 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 has commenced construction of 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. In addition, the states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures couldmay differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. SCE&G defers site assessmentSuch amounts are recorded in regulatory assets and cleanup costs and expects to recover themamortized, 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.DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue until 20142017 and will cost an additional $8.3 million.$20.2 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates and insurance settlements.rates. At December 31, 2011,2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.9$36.7 million and are included in regulatory assets.

PSNC Energy

PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy’s actualActual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. PSNC Energy has recorded a liability and associated regulatory asset of approximately $3.1$2.8 million, the estimated remaining liability at December 31, 2011.2013. PSNC Energy expects to recover through rates any cost net of insurance recovery, allocable to PSNC Energy arising from the remediation of these sites.

Claims and Litigation

In May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette and Mark Rudd, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Communications, Inc. was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiffs alleged that SCE&G made improper use of certain electric transmission easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications and asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment.  While SCE&G and SCI believe their actions were consistent with governing law and the applicable documents granting easements and rights-of-way, this case, with Circuit Court approval in August 2010, has been settled as to all easements and rights of ways currently containing fiber optic communications lines in South Carolina.  This settlement did not have a material impact on the Company’s results of operations, cash flows or financial condition.

The Company is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without a material impact on the Company’s results of operations, cash flows or financial condition.


87



Operating Lease Commitments

The Company is obligated under various operating leases with respect tofor vehicles, office space, furniture and equipment. Leases expire at various dates through 2057. Rent expense totaled approximately $15.8$14.8 million in 2011, $13.92013, $14.8 million in 20102012 and $23.7$15.8 million in 2009.2011. Future minimum rental payments under such leases are as follows:

 

 

Millions of dollars

 

2012

 

$

11

 

2013

 

10

 

2014

 

4

 

2015

 

2

 

2016

 

1

 

Thereafter

 

28

 

Total

 

$

56

 

85



 Millions of dollars
2014$7
20156
20164
20172
20181
Thereafter21
Total$41

Guarantees
Table of Contents

Purchase Commitments

The Company is obligated for purchase commitments that expire at various dates through 2034. Amounts expended under forward contracts for natural gas purchases, gas transportation capacity agreements, coal supply contracts, nuclear fuel contracts, construction projects and other commitments totaled $1.7 billion in 2011, $1.9 billion in 2010 and $1.7 billion in 2009. Future payments under such purchase commitments are as follows:

 

 

Millions of dollars

 

2012

 

$

1,542

 

2013

 

1,037

 

2014

 

897

 

2015

 

804

 

2016

 

801

 

Thereafter

 

1,108

 

Total

 

$

6,189

 

Forward contracts for natural gas purchases include customary “make-whole” or default provisions, but are not considered to be “take-or-pay” contracts.

Guarantees

The CompanySCANA issues guarantees on behalf of its consolidated subsidiaries to facilitate commercial transactions with third parties. These guarantees are in the form of performance guarantees, primarily for the purchase and transportation of natural gas, standby letters of credit issued by financial institutions and credit support for certain tax-exempt bond issues. The CompanySCANA is not required to recognize a liability for such guarantees issued on behalf of its subsidiaries unless it becomes probable that performance under the guarantees will be required. The CompanySCANA believes the likelihood that it would be required to perform or otherwise incur any losses associated with these guarantees is remote; therefore, no liability for these guarantees has been recognized. To the extent that a liability subject to a guarantee has been incurred, the liability is included in the consolidated financial statements.  At December 31, 2011,2013, the maximum future payments (undiscounted) that the CompanySCANA could be required to make under guarantees totaled $1.5 billion.

approximately $1.6 billion.

Asset Retirement Obligations

The Company recognizes a liability for the fairpresent value of an ARO when incurred if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.

The legal obligations associated with the retirement of long-lived tangible assets that results from their acquisition, construction, development and normal operation relate primarily to the Company’s regulated utility operations.  As of December 31, 2011,2013, the Company has recorded an AROAROs of approximately $124$191 million for nuclear plant decommissioning (see Note 1) and an AROAROs of approximately $349$385 million for other conditional obligations primarily related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future.

A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations is as follows:

Millions of dollars

 

2011

 

2010

 

Beginning balance

 

$

497

 

$

477

 

Liabilities incurred

 

1

 

1

 

Liabilities settled

 

(4

)

(1

)

Accretion expense

 

23

 

25

 

Revisions in estimated cash flows

 

(44

)

(5

)

Ending Balance

 

$

473

 

$

497

 

86

Millions of dollars 2013 2012
Beginning balance $561
 $473
Liabilities incurred 6
 
Liabilities settled (4) (5)
Accretion expense 25
 24
Revisions in estimated cash flows (12) 69
Ending balance $576
 $561




Table of Contents

11.          AFFILIATED TRANSACTIONS

The Company received cash distributions from equity-method investees of $5.5$10.4 million in 2013, $12.5 million in 2012 and $5.5 million in 2011 $4.8 million in 2010 and $3.3 million in 2009.. The Company made investments in equity-method investees of $13.6$5.2 million in 2011, $5.12013, $10.6 million in 20102012 and $1.6$13.6 million in 2009.

2011.


88



SCE&G owns 40% of Canadys Refined Coal, LLC, and 10% of Cope Refined Coal, LLC, bothwhich is involved in the manufacturing and selling of refined coal to reduce emissions. SCE&G’s receivables from these affiliates were $8.5 million at December 31, 2011 and insignificant at December 31, 2010.  SCE&G’s payables to these affiliates were $8.6 million at December 31, 2011 and insignificant at December 31, 2010. SCE&G accounts for these investmentsthis investment using the equity method. SCE&G’s receivable from this affiliate was $18.0 million at December 31, 2013 and $1.8 million at December 31, 2012.  SCE&G’s payable to this affiliate was $18.0 million at December 31, 2013 and $1.8 million at December 31, 2012.  SCE&G’s total purchases from this affiliate were $123.8$134.2 million in 20112013 and $97.3$111.6 million in 2010.2012. SCE&G’s total sales to this affiliate were $123.3$133.6 million in 20112013 and $96.9$111.1 million in 2010.

2012.


12.          SEGMENT OF BUSINESS INFORMATION

The Company’s reportable

Reportable segments, which are described below. Thebelow, follow the same accounting policies of the segments are the same as those described in the summary of significant accounting policies.Note 1. The Company records intersegment sales and transfers of electricity and gas based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices.

Electric Operations is primarily engaged in the generation, transmission and distribution of electricity, and is regulated by the SCPSC and FERC.

Gas Distribution, comprised of the local distribution operations of SCE&G and PSNC Energy, is engaged in the purchase and sale, primarily at retail, of natural gas. SCE&G and PSNC Energy are regulated by the SCPSC and the NCUC, respectively.

Retail Gas Marketing markets natural gas in Georgia and is regulated as a marketer by the GPSC. Energy Marketing markets natural gas to industrial and large commercial customers and municipalities, primarily in the Southeast.

All Other is comprised of other direct and indirect wholly-owned subsidiaries of the Company. One of these subsidiaries operates a FERC-regulated interstate pipeline company and the other subsidiaries conduct nonregulated operations in energy-related and telecommunications industries. None of these subsidiaries met the quantitative thresholds for determining reportable segments during any period reported.

The Company’s regulated

Regulated reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However, Electric Operations’ product differs from the other segments, as does its generation process and method of distribution. The marketing segments differ from each other in their respective markets and customer type.

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89



Table of Contents

Disclosure of Reportable Segments (Millions of dollars)

 

 

Electric
Operations

 

Gas
Distribution

 

Retail Gas
Marketing

 

Energy
Marketing

 

All
Other

 

Adjustments/
Eliminations

 

Consolidated
Total

 

2011

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

External Revenue

 

$

2,424

 

$

840

 

$

479

 

$

657

 

$

41

 

$

(32

)

$

4,409

 

Intersegment Revenue

 

8

 

1

 

 

188

 

406

 

(603

)

 

Operating Income

 

616

 

132

 

n/a

 

n/a

 

18

 

47

 

813

 

Interest Expense

 

23

 

24

 

1

 

 

3

 

233

 

284

 

Depreciation and Amortization

 

271

 

65

 

3

 

 

25

 

(18

)

346

 

Income Tax Expense

 

5

 

30

 

16

 

3

 

10

 

104

 

168

 

Income Available to Common Shareholders

 

n/a

 

n/a

 

24

 

4

 

(6

)

365

 

387

 

Segment Assets

 

8,222

 

2,179

 

185

 

114

 

1,377

 

1,457

 

13,534

 

Expenditures for Assets

 

806

 

140

 

 

1

 

17

 

(18

)

946

 

Deferred Tax Assets

 

9

 

12

 

9

 

9

 

17

 

(30

)

26

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

External Revenue

 

$

2,367

 

$

979

 

$

553

 

$

692

 

$

37

 

$

(27

)

$

4,601

 

Intersegment Revenue

 

7

 

1

 

 

182

 

410

 

(600

)

 

Operating Income

 

554

 

140

 

n/a

 

n/a

 

19

 

55

 

768

 

Interest Expense

 

22

 

24

 

1

 

 

3

 

216

 

266

 

Depreciation and Amortization

 

263

 

63

 

4

 

 

29

 

(24

)

335

 

Income Tax Expense

 

(1

)

28

 

19

 

2

 

10

 

101

 

159

 

Income Available to Common Shareholders

 

n/a

 

n/a

 

31

 

4

 

(6

)

347

 

376

 

Segment Assets

 

7,882

 

2,161

 

196

 

116

 

1,322

 

1,291

 

12,968

 

Expenditures for Assets

 

752

 

107

 

 

 

41

 

(24

)

876

 

Deferred Tax Assets

 

5

 

11

 

9

 

5

 

18

 

(27

)

21

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2009

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

External Revenue

 

$

2,141

 

$

948

 

$

522

 

$

616

 

$

37

 

$

(27

)

$

4,237

 

Intersegment Revenue

 

8

 

1

 

 

161

 

416

 

(586

)

 

Operating Income

 

504

 

132

 

n/a

 

n/a

 

19

 

44

 

699

 

Interest Expense

 

15

 

21

 

 

 

4

 

193

 

233

 

Depreciation and Amortization

 

244

 

61

 

4

 

 

28

 

(21

)

316

 

Income Tax Expense

 

 

28

 

15

 

2

 

9

 

113

 

167

 

Income Available to Common Shareholders

 

n/a

 

n/a

 

24

 

3

 

(12

)

333

 

348

 

Segment Assets

 

7,312

 

2,040

 

183

 

99

 

1,205

 

1,255

 

12,094

 

Expenditures for Assets

 

817

 

76

 

 

1

 

130

 

(110

)

914

 

Deferred Tax Assets

 

 

10

 

8

 

6

 

19

 

(43

)

 

 
Electric
Operations
 
Gas
Distribution
 
Retail Gas
Marketing
 
Energy
Marketing
 
All
Other
 
Adjustments/
Eliminations
 
Consolidated
Total
2013             
External Revenue$2,423
 $942
 $465
 $652
 $40
 $(27) $4,495
Intersegment Revenue6
 1
 
 167
 416
 (590) 
Operating Income679
 153
 
 n/a
 27
 51
 910
Interest Expense19
 22
 1
 
 4
 251
 297
Depreciation and Amortization297
 70
 3
 
 26
 (18) 378
Income Tax Expense6
 33
 15
 4
 14
 151
 223
Net Incomen/a
 n/a
 24
 6
 (2) 443
 471
Segment Assets9,488
 2,340
 172
 133
 1,378
 1,653
 15,164
Expenditures for Assets907
 140
 
 1
 31
 27
 1,106
Deferred Tax Assets10
 27
 8
 2
 14
 (61) 
              
2012 
  
  
  
  
  
  
External Revenue$2,446
 $764
 $413
 $543
 $45
 $(35) $4,176
Intersegment Revenue7
 1
 
 125
 416
 (549) 
Operating Income668
 141
 n/a
 n/a
 22
 28
 859
Interest Expense21
 23
 1
 
 3
 247
 295
Depreciation and Amortization278
 67
 3
 
 25
 (17) 356
Income Tax Expense7
 32
 7
 3
 15
 118
 182
Net Incomen/a
 n/a
 11
 5
 1
 403
 420
Segment Assets8,989
 2,292
 153
 122
 1,415
 1,645
 14,616
Expenditures for Assets999
 123
 
 1
 14
 (60) 1,077
Deferred Tax Assets9
 26
 10
 4
 17
 (55) 11
              
2011 
  
  
  
  
  
  
External Revenue$2,424
 $840
 $479
 $657
 $41
 $(32) $4,409
Intersegment Revenue8
 1
 
 188
 406
 (603) 
Operating Income616
 132
 n/a
 n/a
 18
 47
 813
Interest Expense23
 24
 1
 
 3
 233
 284
Depreciation and Amortization271
 65
 3
 
 25
 (18) 346
Income Tax Expense5
 30
 16
 3
 10
 104
 168
Net Incomen/a
 n/a
 24
 4
 (6) 365
 387
Segment Assets8,222
 2,179
 185
 114
 1,377
 1,457
 13,534
Expenditures for Assets806
 140
 
 1
 17
 (18) 946
Deferred Tax Assets9
 12
 9
 9
 17
 (30) 26
Management uses operating income to measure segment profitability for SCE&G and other regulated operations and evaluates utility plant, net, for segments attributable to SCE&G. As a result, SCE&Gthe Company does not allocate interest charges, income tax expense or assets other than utility plant to its segments. For nonregulated operations, management uses net income available to common shareholders as the measure of segment profitability and evaluates total assets for financial position. Interest income is not reported by segment and is not material. The Company’s deferred tax assets are netted with deferred tax liabilities for reporting purposes.

The consolidated financial statements report operating revenues which are comprised of the energy-related and regulated segments. Revenues from non-reportable and nonregulated segments are included in Other Income. Therefore the adjustments to total operating revenues remove revenues from non-reportable segments. Adjustments to Income Available to Common Shareholdersnet income consist of SCE&G’sthe unallocated net income available to common shareholders of SCANA Corporation.

the Company's regulated reportable segments.


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Segment Assets include utility plant, net for SCE&G’s Electric Operations and Gas Distribution, and all assets for PSNC Energy and the remaining segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for SCE&G.

Adjustments to Interest Expense, Income Tax Expense, Expenditures for Assets and Deferred Tax Assets include primarily the totals from SCANA or SCE&G that are not allocated to the segments. Interest Expense is also adjusted to eliminate charges between affiliates. Adjustments to Depreciation and Amortization consist of non-reportable segment expenses, which are not included in the depreciation and amortization reported on a consolidated basis. Expenditures for Assets are adjusted for AFC and revisions to estimated cash flows related to asset retirement obligations. Deferred Tax Assets are adjusted to net them against deferred tax liabilities on a consolidated basis.

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13.          QUARTERLY FINANCIAL DATA (UNAUDITED)

 

 

First
Quarter

 

Second
Quarter

 

Third
Quarter

 

Fourth
Quarter

 

Annual

 

2011 Millions of dollars, except per share amounts

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

 

$

1,281

 

$

1,000

 

$

1,092

 

$

1,036

 

$

4,409

 

Operating income

 

248

 

142

 

215

 

208

 

813

 

Income available to common shareholders

 

128

 

56

 

105

 

98

 

387

 

Basic earnings per share

 

1.00

 

.44

 

.81

 

.76

 

3.01

 

Diluted earnings per share

 

1.00

 

.43

 

.81

 

.75

 

2.97

 

 

 

 

 

 

 

 

 

 

 

 

 

2010 Millions of dollars, except per share amounts

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

 

$

1,428

 

$

939

 

$

1,088

 

$

1,146

 

$

4,601

 

Operating income

 

230

 

137

 

196

 

205

 

768

 

Income available to common shareholders

 

127

 

54

 

101

 

94

 

376

 

Basic earnings per share

 

1.02

 

.43

 

.80

 

.74

 

2.99

 

Diluted earnings per share

 

1.02

 

.43

 

.79

 

.74

 

2.98

 

89


 Millions of dollars, except per share amounts 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 Annual
2013  
  
  
  
  
Total operating revenues $1,311
 $1,016
 $1,051
 $1,117
 $4,495
Operating income 293
 189
 255
 173
 910
Net income 151
 85
 131
 104
 471
Basic earnings per share 1.13
 .60
 .94
 .73
 3.40
Diluted earnings per share 1.11
 .60
 .94
 .73
 3.39
           
2012  
  
  
  
  
Total operating revenues $1,107
 $908
 $1,038
 $1,123
 $4,176
Operating income 238
 171
 238
 212
 859
Net income 121
 72
 122
 105
 420
Basic earnings per share .93
 .55
 .93
 .79
 3.20
Diluted earnings per share .91
 .54
 .91
 .78
 3.15


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SOUTH CAROLINA ELECTRIC & GAS COMPANY

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ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

SCE&G is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity and in the purchase and sale, primarily at retail, and transportation of natural gas. SCE&G’s business is subject to seasonal fluctuations. Generally, sales of electricity are higher during the summer and winter months because of air-conditioning and heating requirements, and sales of natural gas are greater in the winter months due to heating requirements. SCE&G’s electric service territory extends into 24 counties covering nearly 17,000 square miles in the central, southern and southwestern portions of South Carolina. The service area for natural gas encompasses all or part of 35 counties in South Carolina and covers approximately 22,600 square miles.

Key Earnings Drivers and Outlook

During 2011,2013, economic growth showed modest signs of improvementcontinued to improve in the southeast. Significant industrial announcements in SCE&G’s service territory were made during the year.year, and announcements made in previous years began to materialize. In addition, the Port of Charleston continues to see increased traffic, with container volume up 5.7% over 2012.  SCE&G’s residential and commercial customer growth rates also were positive, though customer usage by existing customers continued to decline.positive.  At December 31, 2011,2013, a preliminary estimate of seasonally adjusted unemployment for South Carolina was 9.5%6.6%. Though improved from the 10.9%8.6% unemployment rate at December 31, 2010, unemployment remains high and continues2012, the improvement may be due in part to slowpeople leaving the pace of economic recovery in South Carolina.

workforce. Nationwide the civilian labor force was 62.8% at December 31, 2013, matching a 35-year low.

Over the next five years, key earnings drivers for SCE&G will be additions to utility rate base, consisting primarily of capital expenditures for new generating capacity, environmental facilities and system expansion. Other factors that will impact future earnings growth include the regulatory environment, customer growth and usage and the level of growth of operation and maintenance expenses and taxes.

Electric Operations

The electric operations segment is comprised of the electric operations of SCE&G, GENCO and Fuel Company, and is primarily engaged in the generation, transmission, distribution and sale of electricity in South Carolina. At December 31, 20112013 SCE&G provided electricity to approximately 664,000 customers in an area covering nearly 17,000 square miles.678,000 customers. GENCO owns a coal-fired generating station and sells electricity solely to SCE&G.  Fuel Company acquires, owns, and provides financing for and sells at cost to SCE&G’s&G nuclear fuel, certain fossil fuels and emission and other environmental allowances.

Operating results for electric operations are primarily driven by customer demand for electricity, rates allowed to be charged to customers and the ability to control growth in costs. Through 2013, the effect of weather on operating results was largely mitigated by the eWNA; however, the eWNA was discontinued pursuant to an SCPSC order effective with the first billing cycle of January 2014. Embedded in the rates charged to customers is an allowed regulatory return on equity. SCE&G’s allowed return on equity is 10.7%in 2013 was 10.25% for non-BLRA expenditures, and 11.0% for BLRA-related expenditures. As further described in Note 2 to the consolidated financial statements, SCE&G's allowed return on equity for non-BLRA expenditures was 10.7% prior to 2013. Demand for electricity is primarily affected by weather, customer growth and the economy. SCE&G is able to recover the cost of fuel used in electric generation through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.


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's 2012 IRP identified six coal-fired units that SCE&G has subsequently retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units have an aggregate generating capacity (2012 summer rating) of 730 MW. As of December 31, 2013, three of these units have been retired. For additional information, see Note 1 and Note 2 to the consolidated financial statements.

New Nuclear Construction

SCE&G and Santee Cooper are parties to construction and operating agreements in which they agreed to be joint owners, and share operating costs and generation output, ofis constructing two 1,117-MW1,250 MW (1,117 MW, net) nuclear generation units to be constructed at the site of Summer Station,Station. SCE&G will jointly own the New Units with Santee Cooper, and SCE&G will be responsible for 55 percent of the cost of and receiving 55 percent ofreceive the output andfrom the New Units in proportion to its share of ownership, with Santee Cooper responsible for and receiving the remaining 45 percent.share. SCE&G's current ownership share in the New Units is 55%. Under these agreements,an agreement signed in January 2014

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(and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units. Under the terms of this agreement, SCE&G will have the primary responsibility for oversight of the construction ofacquire a one percent ownership interest in the New Units at the commercial operation date of Unit 2, will acquire an additional two percent ownership interest no later than the first anniversary of such commercial operation date, and will be responsible foracquire the final two percent no later than the second anniversary of such commercial operation date. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units as they come online.

SCE&G, on behalf of itself and as agent for Santee Cooper, has entered into the EPC Contract with the Consortium for the design and construction ofto third parties until the New Units.   Units are complete.


SCE&G’s&G expects Unit 2 to be placed in service in the fourth quarter of 2017 or the first quarter of 2018, with Unit 3's in-service date approximately 12 months later. SCE&G's share of the estimated cash outlays (future value, excluding AFC) for its current 55% ownership share totals approximately $6$5.4 billion for plant costs and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC. The successful completionIn addition, under the terms of the New Units would result in a substantial increase in SCE&G’s utility plant in service.  Financing and managing the construction of these plants, together with continuing environmental construction projects, represents a significant challenge to SCE&G.

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Asagreement previously reported,described, SCE&G has been advised byagreed to pay an amount equal to Santee CooperCooper's actual cost of the percentage conveyed as of the date of conveyance, which SCE&G estimates will be approximately $500 million for the entire 5% interest.


Significant recent developments in new nuclear construction include the following:

In the first quarter of 2013, initial pouring of the Unit 2 nuclear island basemat was completed. The basemat provides a foundation for the containment vessel, shield building and auxiliary building that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, includingmake up the level of its participationnuclear island. The Unit 3 nuclear island basemat was completed in the New Units.  Santee Cooper has entered into a letterfourth quarter of intent with Duke2013.

In April 2013, the 500-ton CR-10 module was set on the Unit 2 basemat. CR-10 supports the containment vessel. Construction of Unit 3's CR-10 module is currently underway.

In May 2013, the containment vessel bottom head for Unit 2 was put in place. The containment vessel will house numerous reactor system components, such as the reactor vessel, steam generator and pressurizer. Work continues in building containment vessel rings that may result in Duke acquiring a portion of Santee Cooper’s ownership interestwill be placed on the containment vessel bottom head for Unit 2.

In September 2013, the reactor vessel cavity for Unit 2 (CA-04 module) was placed in the New Units.

containment vessel bottom head. The Consortiumreactor vessel cavity will house the reactor vessel, which in turn will house the fuel assemblies. The reactor vessel for Unit 2 is on-site.


Fabrication has recently performed an impact study, at SCE&G’s request, relatedbegun for Unit 2's steam generator and refueling canal module (CA-01 module) that will be located inside the containment vessel.

Ring 1 of the Unit 2 containment vessel is scheduled to various cost and timing alternatives arising frombe placed on the delaycontainment vessel bottom head in the issuance datesecond quarter 2014. Ring 2 is scheduled to be placed in the fourth quarter of 2014.

While progress has been made with production, quality assurance and quality control issues, the schedule for fabrication of sub-modules at the contractor facility remains a focus area for the project.

During the fourth quarter of 2013, the Consortium began a full re-baselining of the COL from mid-2011, which wasUnit 2 and Unit 3 construction schedules. SCE&G anticipates that this revised schedule and the date assumed whencost estimate at completion for all non-firm and fixed scopes of work will be finalized in the EPC Contract was signedthird quarter of 2014. SCE&G plans to reevaluate and reschedule its owners cost estimates and cash flow requirements in 2008,light of the new schedule.

For additional information on these and other matters, see New Nuclear Construction Matters herein and Note 2 and Note 10 to the early-2012 issuance date currently anticipated by SCE&G.  SCE&G has recently informed the Consortium that it intends to pursue the alternative that would delay the substantial completion dateconsolidated financial statements.

Environmental
As part of the first New UnitPresident's Climate Action Plan and accelerateby Presidential Memorandum issued June 25, 2013, the substantial completion dateEPA was directed to issue a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The rule became final on January 8, 2014 and requires all new fossil fuel-fired power plants to meet the carbon dioxide emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without carbon capture and sequestration capabilities. Consolidated SCE&G is evaluating the final rule, but does not plan to construct new coal-fired units in the near future. The Memorandum also directed the EPA to issue standards, regulations, or guidelines for existing units by June 1, 2014, to be made final no later than June 1, 2015.

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The CWA provides for the secondimposition of effluent limitations that require treatment for wastewater discharges. New Unitfederal effluent limitation guidelines for steam electric generating units were published in the Federal Register on June 7, 2013, and has also begun discussions concerning the update of cash flow forecasts and construction schedules on that basis.

In December 2011, the NRC granted final design certification to Westinghouse for the AP1000 nuclear reactor, whichELG Rule is the reactorexpected to be used forfinalized May 22, 2014. The EPA expects compliance as soon as possible after July 2017 but no later than July 2020. Additionally, the New Units.  This certificationEPA is a necessary step before the NRC canexpected to issue a COLrule that modifies requirements for existing cooling water intake structures in early 2014, and Congress is expected to consider further amendments to the New Units.  CWA.


In October 2011, the NRC conductedresponse to a mandatory hearing regarding the issuance offederal court order to establish a COLdefinite timeline for the New Units.  This hearing followed the August 2011 completion of the FSER, in which the NRC staff concluded there were no safety aspects that would preclude issuing the COL, and the April 2011 completion of the FEIS, in which the NRC and the USACE concluded there were no environmental impacts that would preclude issuing the COL.

See additional discussion at OTHER MATTERS - Nuclear Generation.

Environmental

Significant federal legislative initiatives related to energy were unsuccessful in 2011, and Consolidated SCE&G expects such legislative initiatives will be hampered through 2012, due to each chamber of Congress being controlled by different political parties. The EPA, however, did issue new rules in 2011 related to air quality, including CSAPR and MATS, which require reductions in power plant emissions of sulfur dioxide, nitrogen oxide and mercury, among other substances.  Though implementation of CSAPR was stayed by the United States Court of Appeals for the District of Columbia pending judicial review, Consolidated SCE&G cannot predict the outcome that judicial review will have on the rule’s implementation. In 2012, additional significant regulatory initiatives bya CCR rule, the EPA and other federal agencieshas said it will likely proceed. These initiatives may require Consolidated SCE&G to build or otherwise acquire generating capacity from energy sources that exclude fossil fuels, nuclear or hydro facilities (for example, under an RES). It is also possible that new initiatives will be introduced to reduce carbon dioxide and other greenhouse gas emissions.  Consolidated SCE&G cannot predict whether such initiatives will be enacted, and if they are, the conditions they would impose on utilities.

The EPA has stated its intention to propose, in late 2012,issue new federal regulations affecting the management and disposal of CCR,CCRs, such as ash.ash, by December 14, 2014. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO.

The EPA is also expectedabove environmental initiatives and other similar issues are described in Environmental Matters herein and in Note 10 to issue regulations during 2012 for cooling water intake structures to meet BACT at existing power generating stations.  Whilethe consolidated financial statements. Unless otherwise noted, Consolidated SCE&G cannot predict how extensive the regulationswhen regulatory rules or legislative requirements for any of these initiatives will be,become final, if at all, or what conditions they may impose on it, if any. Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates.

Gas Distribution

The Gas Distribution segment, comprised of the local distribution operations of SCE&G, is primarily engaged in the purchase, transportation and sale of natural gas to retail customers in portions of South Carolina. At December 31, 20112013 this segment provided natural gas to approximately 317,000 customers in areas covering 22,600 square miles.

329,000 customers.

Operating results for gas distribution are primarily influenced by customer demand for natural gas, rates allowed to be charged to customers and the ability to control growth in costs. Embedded in the rates charged to customers is an allowed regulatory return on equity.

equity of 10.25%.

Demand for natural gas is primarily affected by weather, customer growth, the economy and for commercial and industrial customers, the availability and price of alternate fuels. Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and will impact SCE&G’s ability to

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retain large commercial and industrial customers. One effect ofIn addition, the sluggish economy has been an overall decrease in demand for natural gas which, coupled with discoveriesproduction of shale gas in the United States has resulted in significantly lower prices for this commodity, in 2010 and 2011.  Low natural gas commoditysuch prices are expected to continue in 2012 and beyond.

for the foreseeable future.


RESULTS OF OPERATIONS

Net Income

Net income for Consolidated SCE&G was as follows:

Millions of dollars

 

2011

 

Change

 

2010

 

Change

 

2009

 

Net income

 

$

316.1

 

4.0

%

$

304.0

 

5.7

%

$

287.5

 

Millions of dollars 2013 Change 2012 Change 2011
Net income $390.8
 11.0% $352.0
 11.4% $316.1

·

2011

2013 vs 2010

2012

Net income increased $46.7due to higher electric and gas margins. These margin increases were partially offset by higher operation and maintenance expenses, higher depreciation expense, higher property taxes and higher interest expense, further described below.

2012 vs 2011Net income increased due to higher electric and gas margins. These margin increases were partially offset by higher operation and maintenance expenses, higher depreciation expense, higher property taxes and higher interest expense, further described below.


95




Dividends Declared
Consolidated SCE&G’s Boards of Directors declared the following dividends on common stock (all of which was held by SCANA) during 2013 and 2012:
Declaration DateDividend AmountQuarter EndedPayment Date
February 20, 2013$64.0 millionMarch 31, 2013April 1, 2013
April 25, 2013$63.8 millionJune 30, 2013July 1, 2013
July 31, 2013$67.5 millionSeptember 30, 2013October 1, 2013
October 31, 2013$61.7 millionDecember 31, 2013January 1, 2014
February 15, 2012$53.4 millionMarch 31, 2012April 1, 2012
May 3, 2012$54.1 millionJune 30, 2012July 1, 2012
August 2, 2012$55.8 millionSeptember 30, 2012October 1, 2012
October 24, 2012$45.6 millionDecember 31, 2012January 1, 2013
When a dividend payment date falls on a weekend or holiday, the payment is made the following business day.

Electric Operations
Electric Operations is comprised of the electric operations of SCE&G, GENCO and Fuel Company. Electric operations sales margin (including transactions with affiliates) was as follows:
Millions of dollars 2013 Change 2012 Change 2011
Operating revenues $2,430.5
 (0.9)% $2,453.1
 0.9 % $2,432.2
Less: Fuel used in generation 751.0
 (11.0)% 844.2
 (8.5)% 922.5
          Purchased power 43.0
 53.0 % 28.1
 46.4 % 19.2
Margin $1,636.5
 3.5 % $1,580.8
 6.1 % $1,490.5
2013 vs 2012Margin increased primarily due to base rate increases under the BLRA of $54.2 million and higher electric base rates of $67.3 million approved in the December 2012 rate order. Additionally, pursuant to accounting orders of the SCPSC, 2013's electric margin reflects downward adjustments of $50.1 million to revenue. Such adjustments are fully offset by the recognition within other income of gains realized upon the settlement of certain derivative interest rate contracts, which had been deferred as regulatory liabilities. See Note 2 to the consolidated financial statements.
2012 vs 2011Margin increased primarily by $54.4 million due to an increase in retail electric base rates approved by the SCPSC under the BLRA, by $3.7 million due to customer growth and by $11.0 million due to the expiration of a decrement rider approved in the 2010 retail electric base rate case.

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Sales volumes (in GWh) related to the electric margin above, by class, were as follows:
Classification  2013 Change 2012 Change 2011
Residential 7,571
 
 7,571
 (8.0)% 8,232
Commercial 7,205
 (1.2)% 7,291
 (1.4)% 7,397
Industrial 6,000
 2.8 % 5,836
 (1.7)% 5,938
Other 581
 (0.9)% 586
 2.4 % 572
Total retail sales 21,357
 0.3 % 21,284
 (3.9)% 22,139
Wholesale 955
 (63.2)% 2,595
 26.6 % 2,049
Total 22,312
 (6.6)% 23,879
 (1.3)% 24,188
2013 vs 2012Retail sales volume increased primarily due to customer growth and the effects of weather, partially offset by lower average use. The decrease in wholesale sales is primarily due to the expiration of two customer contracts.
2012 vs 2011Retail sales volume decreased by 983 GWh primarily due to the effects of milder weather. The increase in wholesale sales is primarily due to higher contract utilization by a wholesale customer.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of SCE&G. Gas distribution sales margin (including transactions with affiliates) was as follows:
Millions of dollars 2013 Change 2012 Change 2011
Operating revenues $414.4
 16.5% $355.6
 (8.2)% $387.4
Less: Gas purchased for resale 244.1
 24.2% 196.6
 (18.0)% 239.7
Margin $170.3
 7.1% $159.0
 7.7 % $147.7
2013 vs 2012Margin increased primarily due to the SCPSC-approved increase in base rates under the RSA which became effective with the first billing cycle of November 2012, as well as residential and commercial customer growth.
2012 vs 2011Margin increased $8.3 million due to the SCPSC-approved increases in retail gas base rates under the RSA which became effective with the first billing cycles of November 2011 and 2012.
Sales volumes (in MMBTU) by class, including transportation gas, were as follows:
Classification (in thousands) 2013 Change 2012 Change 2011
Residential 12,515
 23.3% 10,153
 (13.0)% 11,674
Commercial 12,786
 9.1% 11,723
 (2.9)% 12,071
Industrial 20,411
 5.5% 19,341
 14.0 % 16,963
Transportation gas 4,801
 2.0% 4,707
 7.6 % 4,376
Total 50,513
 10.0% 45,924
 1.9 % 45,084
2013 vs 2012Total sales volumes increased primarily due to customer growth, increased industrial usage and the effects of weather.
2012 vs 2011Residential and commercial sales volume decreased primarily due to milder weather. Industrial and transportation sales volumes increased due to the competitive price of gas versus alternate fuel sources.

97



Other Operating Expenses
Other operating expenses were as follows:

Millions of dollars 2013 Change 2012 Change 2011
Other operation and maintenance $556.5
 2.8% $541.6
 5.1% $515.1
Depreciation and amortization 313.4
 6.8% 293.4
 2.6% 286.1
Other taxes 200.2
 6.3% 188.3
 3.2% 182.5

2013 vs 2012Other operation and maintenance expenses increased by $16.7 million due to incremental expenses associated with the December 2012 SCPSC rate order and by $5.7 million due to higher electric margingeneration, transmission and by $1.0 million due to lower operation and maintenancedistribution expenses. This increase was partially offset by $4.1 million due to lower gas margin, higher depreciation expense of $9.1 million, higher property taxes of $6.2 million, higher interest expense of $11.0 million and lower AFC of $5.8 million.

·

2010 vs 2009

Net income increased $72.7 million due to higher electric margin and $6.5 million due to higher gas margin. These increases were partially offset by lower compensation costs of $10.1 million due to reduced headcount and lower incentive compensation accruals and by other general expenses. Depreciation and amortization expense increased $13.2 million due to the recognition of depreciation expense associated with the Wateree Station scrubber which was provided for in the December 2012 SCPSC rate order and due to other net plant additions. Other taxes increased primarily due to higher property taxes on net property additions.

2012 vs 2011Other operation and maintenance expenses increased by $9.3 million due to higher generation, transmission and distribution expenses, of $10.4by $1.7 million due to higher general expenses and by increased$14.2 million due to higher incentive compensation of $5.6 million, byand other benefits. Depreciation and amortization expense increased interest expense of $14.2 million, by lower equity AFC of $8.8 million, byprimarily due to net property additions. Other taxes increased primarily due to higher property taxes of $7.5 million and by $12.9 million due to the tax benefit and related interest income arising from the resolution of an income tax uncertainty in 2009. In late 2009, SCE&G redeemed for cash all outstanding shares of its cumulative preferred stock.

on net property additions.

Pension

Net Periodic Benefit Cost

Pension


     Net periodic benefit cost was recorded on Consolidated SCE&G’s&G's income statements and balance sheets as follows:

Millions of dollars

 

2011

 

2010

 

2009

 

Income Statement Impact:

 

 

 

 

 

 

 

Reduction in employee benefit costs

 

 

$

(2.5

)

$

(4.4

)

Other expense (income)

 

$

0.2

 

(4.2

)

(4.0

)

Balance Sheet Impact:

 

 

 

 

 

 

 

Increase in capital expenditures

 

3.4

 

5.3

 

9.1

 

Component of amount receivable from Summer Station co-owner

 

1.2

 

1.7

 

2.7

 

Increase in regulatory asset

 

9.1

 

18.6

 

31.2

 

Total Pension Cost

 

$

13.9

 

$

18.9

 

$

34.6

 

Millions of dollars 2013 Change 2012 Change 2011
Income Statement Impact:          
   Employee benefit costs $11.0
 100.0% 
 
 
   Other expense 0.6
 50.0 % $0.4
 100.0% $0.2
Balance Sheet Impact:          
   Increase in capital expenditures 6.4
 12.3 % 5.7
 67.6% 3.4
   Component of amount receivable from Summer Station co-owner 2.5
 13.6 % 2.2
 83.3% 1.2
   Increase in regulatory asset 5.5
 (63.3)% 15.0
 64.8% 9.1
 Net periodic benefit cost $26.0
 11.6 % $23.3
 67.6% $13.9

Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts included in rates for its retail electric and gas distribution regulated operations. In connection with the SCPSC’sSCPSC's July 2010 electric rate order and November 2010 natural gas RSA order, SCE&G began deferring, as a regulatory asset, all pension costcosts related to retail electric and gas operations that otherwise would have been charged to expense. TheseEffective in January 2013, in connection with the December 2012 rate order, SCE&G began amortizing previously deferred pension cost related to retail electric operations totaling approximately $63 million over approximately 30 years (see Note 2) and recovering current pension costs willrelated to retail electric operations through a rate rider that may be adjusted annually. Similarly, in connection with the October 2013 RSA order, deferred until such time as future rate recoverypension cost related to gas operations of approximately $14 million is provided for by the SCPSC.

No contributionbeing amortized over approximately 14 years, and effective November 2013, SCE&G is recovering current pension expense related to gas operations through cost of service rates (see Note 2 to the pension trust was necessary, nor did limitations on benefit payments apply, in orconsolidated financial statements). In 2013, such amortizations totaled approximately $2.0 million for any period reported.

electric operations and $0.2 million for gas operations.



98



Other Income (Expense)
Other income (expense) includes the results of certain non-utility activities. Components of other income (expense), were as follows:
Millions of dollars 2013 Change 2012 Change 2011
Other income $52.7
 * $0.4
 (91.8)% $4.9
Other expense (17.5) (2.2)% (17.9) 51.7 % (11.8)
Total $35.2
 * $(17.5) * $(6.9)
*Greater than 100%
2013 vs 2012Total other income (expense) increased primarily due to the recognition, pursuant to SCPSC accounting orders, of $50.1 million of gains realized upon the 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 regulatory liabilities. Such gain recognition was fully offset by downward adjustments to revenues reflected within electric margin and had no effect on net income.
2012 vs 2011Total other income (expense) decreased primarily due to higher non-utility related employee benefit costs in 2012.
AFC

AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. Consolidated SCE&G includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 4.5%6.6% of income before income taxes in 2013, 6.3% in 2012 and 4.5% in 2011, 6.6% in 2010 and 11.5% in 2009, respectively.

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Table of Contents

Dividends Declared

Consolidated SCE&G’s Boards of Directors declared the following dividends on common stock (all of which was held by SCANA) during 2011 and 2010:

Declaration Date

Dividend Amount

Quarter Ended

Payment Date

February 11, 2011

$

50.6 million

March 31, 2011

April 1, 2011

April 21, 2011

49.0 million

June 30, 2011

July 1, 2011

August 11, 2011

50.5 million

September 30, 2011

October 1, 2011

October 26, 2011

39.3 million

December 31, 2011

January 1, 2012

February 11, 2010

$

46.6 million

March 31, 2010

April 1, 2010

May 6, 2010

47.2 million

June 30, 2010

July 1, 2010

July 29, 2010

50.7 million

September 30, 2010

October 1, 2010

October 27, 2010

54.5 million

December 31, 2010

January 1, 2011

Electric Operations

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

Millions of dollars

 

2011

 

Change

 

2010

 

Change

 

2009

 

Operating revenues

 

$

2,432.2

 

2.5

%

$

2,373.9

 

10.5

%

$

2,148.9

 

Less: Fuel used in generation

 

922.5

 

(2.6

)%

946.7

 

15.1

%

822.3

 

Purchased power

 

19.2

 

12.9

%

17.0

 

1.2

%

16.8

 

Margin

 

$

1,490.5

 

5.7

%

$

1,410.2

 

7.7

%

$

1,309.8

 

·

2011 vs 2010

Margin increased by $49.0 million due to an increase in retail electric base rates approved by the SCPSC under the BLRA and by $34.5 million due to an SCPSC-approved increase in retail electric base rates in July 2010. Also, margin in the first quarter of 2010 was adjusted downward by $17.4 million pursuant to an SCPSC regulatory order in connection with SCE&G’s annual fuel cost proceeding. These increases were partially offset by $12 million due to the effects of weather in 2010 before the implementation of the SCPSC-approved eWNA and by lower customer usage of $8.7 million.

·

2010 vs 2009

Margin increased by $37.0 million due to higher SCPSC-approved retail electric base rates in July 2010 and by $30.7 million due to an increase in base rates approved by the SCPSC under the BLRA. In addition, margin increased by $54.2 million (net of eWNA after its implementation) due to weather, by $5.8 million due to higher transmission revenue and off-system sales and by $13.6 million due to the adoption of SCPSC-approved lower electric depreciation rates in 2009, the effect of which was offset by a reduction in the recovery of fuel costs (electric revenue). During the first quarter of 2010, SCE&G deferred $25 million of incremental revenue as a result of the abnormally cold weather in its service territory (see Note 2 to the consolidated financial statements). Also, margin in the first quarter of 2010 was adjusted downward by $17.4 million pursuant to an SCPSC regulatory order issued in connection with SCE&G’s annual fuel cost proceeding. (See also discussion at “Income Taxes”.) Finally, pursuant to the SCPSC-approved retail electric base rate order in 2010, SCE&G adopted an eWNA thereby mitigating the effects of abnormal weather on its margins.

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

Classification 

 

2011

 

Change

 

2010

 

Change

 

2009

 

Residential

 

8,232

 

(6.4

)%

8,791

 

11.4

%

7,893

 

Commercial

 

7,397

 

(3.7

)%

7,684

 

4.5

%

7,350

 

Industrial

 

5,938

 

1.3

%

5,863

 

10.1

%

5,324

 

Other

 

572

 

(1.5

)%

581

 

3.4

%

562

 

Total retail sales

 

22,139

 

(3.4

)%

22,919

 

8.5

%

21,129

 

Wholesale

 

2,049

 

4.3

%

1,965

 

(0.5

)%

1,975

 

Total

 

24,188

 

(2.8

)%

24,884

 

7.7

%

23,104

 

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Table of Contents

·

2011 vs 2010

Total retail sales volumes decreased by 775 GWh due to weather.

·

2010 vs 2009

Total retail sales volumes increased by 1,209 GWh due to weather and by 539 GWh due to higher industrial sales volumes.

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

 

2011

 

Change

 

2010

 

Change

 

2009

 

Operating revenues

 

$

387.4

 

(12.3

)%

$

441.6

 

5.1

%

$

420.1

 

Less: Gas purchased for resale

 

239.7

 

(16.6

)%

287.4

 

4.0

%

276.3

 

Margin

 

$

147.7

 

(4.2

)%

$

154.2

 

7.2

%

$

143.8

 

·

2011 vs 2010

Margin decreased $8.2 million due to the SCPSC-approved decrease in retail gas base rates which became effective with the first billing cycle of November 2010. This decrease was partially offset by an increase of $1.8 million due to the SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2011.

·

2010 vs 2009

Margin increased $9.2 million due to the SCPSC-approved increase in retail gas base rates which became effective with the first billing cycle of November 2009 and $3.3 million due to increased customer usage. These increases were partially offset by a decrease of $2.2 million due to a SCPSC-approved decrease in retail gas base rates which became effective with the first billing cycle of November 2010.

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

Classification (in thousands)

 

2011

 

Change

 

2010

 

Change

 

2009

 

Residential

 

11,674

 

(21.9

)%

14,954

 

20.7

%

12,386

 

Commercial

 

12,071

 

(8.9

)%

13,255

 

4.1

%

12,736

 

Industrial

 

16,963

 

2.8

%

16,497

 

11.1

%

14,853

 

Transportation gas

 

4,376

 

16.7

%

3,749

 

12.8

%

3,323

 

Total

 

45,084

 

(7.0

)%

48,455

 

11.9

%

43,298

 

·

2011 vs 2010

Residential and commercial sales decreased primarily due to milder weather. Industrial and transportation sales increased primarily as a result of improved economic conditions and the competitive price of gas versus alternate fuel sources.

·

2010 vs 2009

Residential sales volume increased primarily due to customer growth and weather. Commercial and industrial sales volume increased primarily as a result of improved economic conditions.

Other Operating Expenses

Other operating expenses were as follows:

Millions of dollars

 

2011

 

Change

 

2010

 

Change

 

2009

 

Other operation and maintenance

 

$

515.1

 

0.1

%

$

514.4

 

5.0

%

$

489.8

 

Depreciation and amortization

 

286.1

 

5.5

%

271.3

 

6.4

%

255.1

 

Other taxes

 

182.5

 

4.5

%

174.7

 

7.9

%

161.9

 

·

2011 vs 2010

Other operation and maintenance expenses increased primarily due to higher generation, transmission and distribution expenses. Depreciation and amortization expense increased primarily due to net property additions. Other taxes increased primarily due to higher property taxes.

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Table of Contents

·

2010 vs 2009

Other operation and maintenance expenses increased by $16.9 million due to higher generation, transmission and distribution expenses and by $9.0 million due to higher incentive compensation and other benefits. Depreciation and amortization expense increased primarily due to net property additions. Other taxes increased primarily due to higher property taxes.

Other Income (Expense)

Other income (expense) includes the results of certain non-utility activities. Components of other income (expense), were as follows:

Millions of dollars

 

2011

 

Change

 

2010

 

Change

 

2009

 

Other income

 

$

4.9

 

(59.5

)%

$

12.1

 

(57.7

)%

$

28.6

 

Other expense

 

(11.8

)

(21.9

)%

(15.1

)

33.6

%

(11.3

)

Total

 

$

(6.9

)

 

*

$

(3.0

)

 

*

$

17.3

 


*Greater than 100%

·

2011 vs 2010

Total other income (expense) decreased primarily due to lower pension income in 2011.

·

2010 vs 2009

Total other income (expense) decreased $16.0 million due to decreased interest income. In September 2009, as a result of a favorable decision by the South Carolina Supreme Court, SCE&G was refunded previously contested EIZ Credits of $15.3 million and an additional $14.3 million of interest income. SCE&G recorded a multi-year catch-up adjustment in the third quarter of 2009 of approximately $6.3 million ($4.0 million after federal tax effect) as a reduction in income taxes. The interest income of $14.3 million ($8.8 million after tax effect) was recorded in the third quarter of 2009 within other income.

Interest Expense


Components of interest expense, net of the debt component of AFC, were as follows:

Millions of dollars

 

2011

 

Change

 

2010

 

Change

 

2009

 

Interest on long-term debt, net

 

$

191.0

 

7.3

%

$

178.0

 

13.9

%

$

156.3

 

Other interest expense

 

13.5

 

55.2

%

8.7

 

17.6

%

7.4

 

Total

 

$

204.5

 

9.5

%

$

186.7

 

14.1

%

$

163.7

 

Millions of dollars 2013 Change 2012 Change 2011
Interest on long-term debt, net $206.8
 3.0% $200.7
 5.1 % $191.0
Other interest expense 10.5
 7.1% 9.8
 (27.4)% 13.5
Total $217.3
 3.2% $210.5
 2.9 % $204.5
Interest on long-term debt increased in each year primarily due to increased long-term borrowings over the prior year.borrowings. Other interest expense increased in each year2013 and decreased in 2012, primarily due to higherreductions in principal balances outstanding on short-term debt over the respective prior year.

Income Taxes

Income tax expense (and the effective tax rate) increasedyear and also decreased in 2011 over 2010 primarily2012 due to the accelerated amortizationreversal in 2012 of deferred EIZ Creditsinterest which had been accrued in 2011 related to offset undercollected fuel costs in 2010 pursuant to an SCPSC order and an increase in operating income.  Incomea tax expense (and the effective tax rate) decreased in 2010 over 2009 primarily due to the above-mentioned accelerated amortization of EIZ Credits to offset undercollected fuel costs and the accelerated amortization of EIZ Credits in connection with the July 2010 retail electric rate order. (Seeuncertainty that was resolved (see Note 5 to the consolidated financial statements for reconciling differences between incomestatements).


Income Taxes
Income tax expense increased in 2013 over 2012 and statutoryin 2012 over 2011 primarily due to increases in income before taxes. The increase in the effective tax expense.)

rate in 2013 is principally attributable to lower recognition of EIZ Credits upon the completion of the amortization of certain such credits in 2012.

LIQUIDITY AND CAPITAL RESOURCES

Consolidated SCE&G anticipates that its contractual cash obligations will be met through internally generated funds and the incurrence of additional short- and long-term indebtedness and capital contributions from SCANA.indebtedness. Consolidated SCE&G expects that, barring a future impairment of the capital markets, it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future.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 year ended December 31, 20112013 was 3.13.

3.48.


99



Consolidated SCE&G’s cash requirements arise primarily from its operational needs, funding its construction programs and payment of dividends to SCANA. The ability of Consolidated SCE&G to replace existing plant investment, to expand to meet future demand for electricity and gas and to install equipment necessary to comply with environmental

96



Table of Contents

regulations, will depend upon its ability to attract the necessary financial capital on reasonable terms. Consolidated SCE&G recovers the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and Consolidated SCE&G continues its ongoing construction program, Consolidated SCE&G expects to seek increases in rates. Consolidated SCE&G’s future financial position and results of operations will be affected by Consolidated SCE&G’s ability to obtain adequate and timely rate and other regulatory relief.


Cash outlays for property additions and construction expenditures, including nuclear fuel, net of AFC were $786  million$1.0 billion in 20112013 and are estimated to be $1.3$1.5 billion in 2012.

2014.

Consolidated SCE&G’s current estimates of its capital expenditures for construction and nuclear fuel for 2012-2014,2014-2016, which are subject to continuing review and adjustment, are as follows:

Estimated Capital Expenditures

Millions of dollars

 

2012

 

2013

 

2014

 

Consolidated SCE&G - Normal

 

 

 

 

 

 

 

Generation

 

$

143

 

$

96

 

$

79

 

Transmission & Distribution

 

197

 

217

 

190

 

Other

 

26

 

14

 

21

 

Gas

 

49

 

51

 

57

 

Common

 

14

 

18

 

13

 

Total Consolidated SCE&G - Normal

 

429

 

396

 

360

 

New Nuclear

 

954

 

952

 

727

 

Cash Requirements for Construction

 

1,383

 

1,348

 

1,087

 

Nuclear Fuel

 

44

 

110

 

55

 

Total Estimated Capital Expenditures

 

$

1,427

 

$

1,458

 

$

1,142

 

Millions of dollars 2014 2015 2016
Consolidated SCE&G - Normal  
  
  
Generation $136
 $145
 $112
Transmission & Distribution 230
 280
 258
Other 14
 25
 19
Gas 50
 51
 73
Common 9
 7
 10
Total Consolidated SCE&G - Normal 439
 508
 472
New Nuclear (including transmission) 950
 905
 667
Cash Requirements for Construction 1,389
 1,413
 1,139
Nuclear Fuel 67
 30
 147
Total Estimated Capital Expenditures $1,456
 $1,443
 $1,286
Estimated capital expenditures for Nuclear Fuel in 2016 include approximately $53 million, which is SCE&G's share of nuclear fuel it acquired in 2013. This fuel has been recorded in utility plant and the corresponding obligation has been recorded in long-term debt on the consolidated balance sheet.

Consolidated SCE&G’s contractual cash obligations as of December 31, 20112013 are summarized as follows:

Contractual Cash Obligations

 

 

Payments due by period

 

Millions of dollars

 

Total

 

Less than
1 year

 

1 - 3 years

 

4 - 5 years

 

More than
5 years

 

Long-term and short-term debt including interest

 

$

7,204

 

$

716

 

$

746

 

$

359

 

$

5,383

 

Capital leases

 

7

 

2

 

3

 

2

 

 

Operating leases

 

37

 

7

 

9

 

 

21

 

Purchase obligations

 

4,335

 

955

 

2,306

 

412

 

662

 

Other commercial commitments

 

1,991

 

641

 

557

 

207

 

586

 

Total

 

$

13,574

 

$

2,321

 

$

3,621

 

$

980

 

$

6,652

 

  Payments due by period
Millions of dollars Total 
Less than
1 year
 1 - 3 years 4 - 5 years 
More than
5 years
Long-term and short-term debt including interest $8,403
 $510
 $653
 $1,090
 $6,150
Capital leases 12
 2
 6
 2
 2
Operating leases 30
 5
 6
 1
 18
Purchase obligations 3,669
 1,802
 1,646
 221
 
Other commercial commitments 2,524
 527
 713
 571
 713
Total $14,638
 $2,846
 $3,024
 $1,885
 $6,883
Included in the table above in purchase obligations is SCE&G’s portion of a contractual agreement for the design and construction of the New Units at the Summer Station site. SCE&G expects to be a joint owner and share operating costs and generation output of the New Units, with SCE&G accountingcurrently responsible for 55 percent of the cost and receiving 55 percent of the output, and other joint owner(s)owner (or owners) the remaining 45 percent.  SCE&G’s estimated projected costs for the two additional units, in future dollars and excluding AFC, are summarized below. To the extent that actual contracts were put in place by December 31, 2011, obligations arising from these contracts areAlso included in the purchase obligations withintable above is the Contractual Cash Obligations table above.

Future Value
Millions of dollars

 

2012

 

2013

 

2014

 

2015

 

2016

 

After 2016

 

Total Project Cash Outlay

 

$

804

 

$

825

 

$

558

 

$

575

 

$

367

 

$

232

 

estimated $500 million SCE&G expects it will cost to acquire an additional 5% ownership in the New Units as further described in New Nuclear Construction Matters.


100



Also included in purchase obligations are customary purchase orders under which SCE&G has the option to utilize certain vendors without the obligation to do so. SCE&G may terminate such arrangements without penalty.

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Table of Contents

Included in other commercial commitments are estimated obligations for coal and nuclear fuel purchases. SCE&G also has a legal obligation associated with the decommissioning and dismantling of Summer Station Unit 1 and other conditional asset retirement obligations that are not listed in the contractual cash obligations above. See Notes 1 and 10 to the consolidated financial statements.

In addition, Consolidated SCE&G is party to certain NYMEX futures contracts for which any unfavorable market movements are funded in cash. These derivatives are accounted for as cash flow hedges and their effects are reflected within other comprehensive income until the anticipated sales transactions occur. See further discussion at Item 7A. Quantitative and Qualitative Disclosures About Market Risk.


At December 31, 2011,2013, Consolidated SCE&G had posted $45$1.5 million in cash collateral for interest rate derivative contracts.

Financing Limits and Related Matters

Consolidated SCE&G’s issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by regulatory bodies including the SCPSC and FERC. Financing programs currently utilized by Consolidated SCE&G are as follows.

follow.

SCE&G and GENCO havehas obtained FERC authority to issue short-term indebtedness (pursuantand to assume liabilities as a guarantor(pursuant to Section 204 of the Federal Power Act). SCE&G may issue up to $1.2 billion of unsecured promissory notes, or commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, bankers, and dealers in commercial paper in amounts not to exceed $600 million. GENCO mayhas obtained FERC authority to issue upshort-term indebtedness not to exceed $150 million outstanding with maturity dates of short-term indebtedness.one year or less. The authority to make such issuancesdescribed herein will expire in October 2012.

2014.

In October 2013, the Consolidated SCE&G's existing committed LOCs were extended by one year. As a result, at December 31, 2013 SCE&G and Fuel Company arewere parties to five-year credit agreements in the amountamounts of $1.1$1.2 billion, of(of which $400$500 million relates to Fuel Company,Company) which expire in October 23, 2015.2018. In addition, at December 31, 2013 SCE&G was 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’scompany'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 linesFor a list of banks providing credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A.support and Morgan Stanley Bank, N.A. each provide 10% ofother information, see Note 4 to the aggregate $1.5 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provide 8%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%.  Three other banks provide the remaining 6%. These bank credit facilities support the issuance of commercial paper by SCE&G (including Fuel Company). When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCE&G (including Fuel Company).

At December 31, 2011 and 2010, 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

 

 

 

2011

 

2010

 

Lines of credit:

 

 

 

 

 

Committed long-term

 

 

 

 

 

Total

 

$

1,100

 

$

1,100

 

LOC advances

 

 

 

Weighted average interest rate

 

 

 

Outstanding commercial paper (270 or fewer days)

 

$

512

 

$

381

 

Weighted average interest rate

 

.56

%

.42

%

Letters of credit supported by an LOC

 

$

.3

 

$

.3

 

Available

 

$

588

 

$

719

 

consolidated financial statements.

As of December 31, 2011,2013, Consolidated SCE&G had no outstanding borrowings under its $1.1$1.4 billion facilities, had approximately $512$251 million in commercial paper borrowings outstanding, was obligated under $.3$0.3 million in LOC-supported letters of credit, and had approximately $16$92 million in cash and temporary investments. Consolidated SCE&G regularly monitors the commercial paper and short-term credit markets to optimize the timing for repayment of the outstanding balance

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on its draws, while maintaining appropriate levels of liquidity. Average short-term borrowings outstanding during 20112013 were approximately $485$369 million. Short-term cash needs were met primarily through the issuance of commercial paper.

At December 31, 2011, Consolidated SCE&G had net available liquidity of approximately $604 million, and its revolving credit facilities are in place until October 2015.2013, Consolidated SCE&G’s long-term debt portfolio has a weighted average maturity of over 18approximately 20 years and bears an average cost of 6.18%5.66%. MostSubstantially all of Consolidated SCE&G's long-term debt other than facility draws, effectively 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’s Restated Articles of Incorporation do not limit the dividends that may be paid on its common stock. However, SCE&G’s bond indenture contains provisions that, under certain circumstances, which SCE&G considers to be remote, could limit the payment of cash dividends on its common stock, all of which is beneficially owned by SCANA.

With respect to hydroelectric projects, the

The Federal Power Act requires the appropriation of a portion of certain earnings therefrom.from hydroelectric projects. At December 31, 2011,2013, approximately $58.8$63.1 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.

SCE&G is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its first mortgage bonds (Bonds) have been issued. Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, other than certain Bonds issued on the basis of retired Bonds, may be issued under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12

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consecutive months out of the 18 months immediately preceding the month of issuance are at least twice (2.0) the annual interest requirements on all outstanding Bonds and Bonds to be outstanding (Bond Ratio). For the year ended December 31, 2011,2013, the Bond Ratio was 5.37.

5.28.

Financing Activities


In June 2013, SCE&G issued $400 million of 4.60% first mortgage bonds due June 15, 2043. Proceeds from this sale were used to pay at maturity $150 million of its 7.125% first mortgage bonds due June 15, 2013, to repay short-term debt primarily incurred as a result of SCE&G's construction program, to finance capital expenditures, and for general corporate purposes.

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

In January 2013, JEDA issued for the benefit of SCE&G $39.5 million of 4.0% tax-exempt industrial revenue bonds due February 1, 2028, and $14.7 million of 3.625% tax-exempt industrial revenue bonds due February 1, 2033. Proceeds from these sales were loaned by JEDA to SCE&G and, together with other available funds, were used to redeem prior to maturity $56.9 million of 5.2% industrial revenue bonds due November 1, 2027.
In November 2012, SCE&G repaid at maturity $4.4 million of 4.2% tax-exempt industrial revenue bonds, and repaid prior to maturity $29.2 million of 5.45% tax-exempt industrial revenue bonds due November 1, 2032.

In July 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042.2042 (issued at a premium with a yield of 3.86%), which constituted a reopening of the prior offering of $250 million of 4.35% first mortgage bonds which were issued in January 2012. Proceeds from the salethese sales were used to repay short-term debt primarily incurred as a result of ourSCE&G's construction program, to finance capital expenditures and for general corporate purposes.

In October 2011, SCE&G issued $30 million of 3.22% first mortgage bonds due October 18, 2021.  Proceeds from the sale


 During 2013 there were used to redeem prior to maturity $30 million of 5.7% pollution control facilities revenue bonds due November 1, 2024 issued by Orangeburg County, South Carolina, on SCE&G’s behalf.

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

During 2011 Consolidated SCE&G experienced net cash inflows related to financing activities of $193$49 million primarily due to the issuance of short-term and long-term debt and contributioncontributions from parent, partially offset by repayment of short- and long-term debt and payment of dividends.


Investing Activities

SCE&G paid approximately $31$6 million, in 2011net, through the third quarter of 2013 to settle interest rate derivative contracts associated withupon the issuance of long-term debt for contracts that had been designated as hedges.

In addition, during the fourth quarter of 2013, SCE&G received approximately $120 million upon the settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt.

Pursuant to SCPSC accounting orders, $50.1 million of such gains were recognized within other income, with such gain recognition being fully offset by downward adjustments to revenues reflected within electric margin.

In February 2014, Consolidated SCE&G’s Boards of Directors declared dividends on common stock of $64.3 million, payable on April 1, 2014.

For additional information, on significant financing transactions, see Note 4 to the consolidated financial statements.


In December 2010, the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 (Tax Relief Act) was signed into law.  Major tax incentives in the Tax Relief Act included 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 and 50% bonus depreciation for property placed in service for 2012.  The American Taxpayer Relief Act of 2012 extended the 50% bonus depreciation for property placed in service in 2013.  These incentives, along with certain other deductions, have had a positive impact on the cash flows of Consolidated SCE&G.


ENVIRONMENTAL MATTERS

Consolidated SCE&G’s regulated 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. Compliance with these

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environmental

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environmental requirements involves significant capital and operating costs, which the CompanyConsolidated SCE&G expects to recover through existing ratemaking provisions.

For the three years ended December 31, 2011,2013, Consolidated SCE&G’s&G's capital expenditures for environmental control equipment at its fossil fuel generating stations totaled $164.0$46.1 million. In addition, Consolidated SCE&G made expenditures to operate and maintain environmental control equipment at its fossil plants of $9.2 million in 2013, $10.2 million in 2012 and $7.9 million during 2011, $6.5 million during 2010, and $5.6 million during 2009, which are included in “Other operation and maintenance” expense, and made expenditures to handle waste ash of $3.2 million in 2013, $7.9 million in 2012 and $8.7 million in 2011, $5.9 million in 2010, and $6.5 million in 2009, which are included in “Fuel used in electric generation.” In addition, included within “Other operation and maintenance” expense is an annual amortization of $1.4 million in each of 2011, 2010,2013, 2012 and 20092011 related to SCE&G’s&G's recovery of MGP remediation costs as approved by the SCPSC. It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for Consolidated SCE&G are $35.0$9.5 million for 20122014 and $126.1$82.5 million for the four-year period 2013-2016.2015-2018.  These expenditures are included in Consolidated SCE&G’s&G Estimated Capital Expenditures table, are discussed in Liquidity and Capital Resources, and include known costs related to the matters discussed below.


At the state level, no significant environmental legislation that would affect Consolidated SCE&G’s operations advanced during 2011.2013. Consolidated SCE&G cannot predict whether such legislation will be introduced or enacted in 2012,2014, or if new regulations or changes to existing regulations at the state level will be implemented in the coming year. Several regulatory initiatives at the federal level did advance in 20112013 and more are expected to advance in 20122014 as described below.

Air Quality

With the pervasive emergence of concern over the issue of global climate change as a significant influence upon the economy, Consolidated SCE&G is subject to climate-related financial risks, including those involving regulatory requirements responsive to GHG emissions, as well as those involving other potential physical impacts which could arise from global climate change.impacts. Other business and financial risks arising from such climate change could also arise.materialize. Consolidated SCE&G cannot predict all of the climate-related regulatory and physical risks nor the related consequences which might impact Consolidated SCE&G, and the following discussion should not be considered all-inclusive.


As part of the President's Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA was directed to issue a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The rule became final on January 8, 2014 and requires all new fossil fuel-fired power plants to meet the carbon dioxide emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without carbon capture and sequestration capabilities. Consolidated SCE&G is evaluating the final rule, but does not plan to construct new coal-fired units in the near future. The Memorandum also directed the EPA to issue standards, regulations, or guidelines for existing units by June 1, 2014, to be made final no later than June 1, 2015. Consolidated SCE&G also cannot predict when rules will become final for existing units, if at all, or what conditions they may impose on Consolidated SCE&G, if any. Consolidated SCE&G expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

From a regulatory perspective, Consolidated SCE&G and GENCO continually monitorsmonitor and evaluatesevaluate their current and projected emission levels and strivesstrive to comply with all state and federal regulations regarding those emissions. Consolidated SCE&G participatesand GENCO participate in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also hashave constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in pre-constructionconstruction 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 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels.  CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide.  SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements.  On July 6, 2011 the EPA issued the CSAPR.  This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. On August 21, 2012, the Court of Appeals vacated CSAPR and left CAIR in place. The EPA's petition for rehearing of the Court of Appeals' order was denied. In June 2013 the U.S. Supreme Court agreed to review

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the Court of Appeals' decision and oral arguments were held on December 10, 2013. A decision is still pending. Air quality control installations that SCE&G and GENCO have already completed should assist the Company in complyinghave allowed Consolidated SCE&G to comply with the reinstated CAIR and will also allow it to comply with CSAPR, and the reinstated CAIR.if reinstated. Consolidated SCE&G will continue to pursue strategies to comply with all applicable environmental regulations.  Any costs incurred to comply with such regulations are expected to be recoverable through rates.

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


The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the NSPS of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In June 2010,addition, the DOJ, on behalf of the EPA, issued a final rulehas taken civil enforcement action against several utilities. The primary basis for a one-hour ambient air quality standard for sulfur dioxide. This new standard may require some of SCE&G’s smaller coal-fired units to reduce their sulfur dioxide emissions to a level to be determinedthese actions is the assertion by the EPA and/or DHEC. Thethat maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement. Though Consolidated SCE&G cannot predict what action, if any, the EPA will initiate against it, any costs incurred to comply with this new standard are expected to be recoveredrecoverable through rates.


Physical effects associated with climate changes could include the impact of possible changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to Consolidated SCE&G’s electric system, as well as impacts on employees and customers and on its supply chain and many others. Much of the service territory of SCE&G is subject to the damaging effects of Atlantic and Gulf coast hurricanes and also to the damaging impact of winter ice storms.

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To help mitigate the financial risks arising from these potential occurrences, SCE&G maintains insurance on certain properties andproperties. In addition, SCE&G has collected funds from customers for its storm damage reserve (see Note 2 to the consolidated financial statements). As part of its ongoing operations, SCE&G maintains emergency response and storm preparation plans and teams and applicable personnel participate inwho receive ongoing training and related simulations in advance of such storms, all in order to allow Consolidated SCE&G to protect its assets and to return its systems to normal reliable operation in a timely fashion following any such event.

In December 2009, the EPA issued a final finding that atmospheric concentrations of GHG endanger public health and welfare within the meaning of Section 202(a) of the CAA. The rule, which became effective in January 2010, enables the EPA to regulate GHG emissions under the CAA. The EPA has committed to issue new rules regulating such emissions in 2012. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units. In March 2011, the EPA proposed new standards for mercury and other specified air pollutants. The rule, which becomes effective April 16, 2012, provides up to four years for facilities to meet the standards. The rule is currently being evaluated by Consolidated SCE&G. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the new source performance standards of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement.

To date, SCE&G and GENCO have received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. The current state of continued DOJ civil enforcement is the subject of industry-wide speculation, and it cannot be determined whether Consolidated SCE&G will be affected by the initiative in the future. Consolidated SCE&G believes that any enforcement action relative to its compliance with the CAA would be without merit. Consolidated SCE&G further believes that installation of equipment responsive to CAIR previously discussed will mitigate many of the alleged concerns with NSR.

Water Quality

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 nationalfacility’s NPDES permit program. Discharge permits have been issuedis 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 renewed for all of SCE&G’s and GENCO’s generating units. Concurrent with renewal of these permits, the permitting agency has implemented a more rigorous program of monitoring and controlling discharges, has modified the requirements for new cooling water intake structures, and has required strategies for toxicity reduction in wastewater streams.is expected to be finalized May 22, 2014. The EPA has said that it willexpects compliance as soon as possible after July 2017 but no later than July 2020.

Additionally, the EPA is expected to issue a rule by mid 2012 that modifies requirements for existing cooling water intake structures.structures in early 2014. Consolidated SCE&G is conducting studies and is developing or implementing compliance plans for these initiatives. Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones and toxicity-based standards.zones. These provisions, if passed, could have a material impact on the financial condition, results of operations and cash flows of the Consolidated SCE&G.&G and GENCO. Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates.

Hazardous and Solid Wastes

The

In response to a federal court order to establish a definite timeline for a CCR rule, the EPA stated its intention to propose in late 2012has said it will issue new federal regulations affecting the management and disposal of CCRs, such as ash.ash, by December 2014. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO. While Consolidated SCE&G cannot predict how extensive the regulations will be, Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates.

The final CCR rule may require the closure of ash ponds.  SCE&G has three generating facilities that have employed ash storage ponds, and all of these ponds have either been closed after all ash was removed or are part of an ash pond closure project that includes complete removal of the ash prior to closure.  The electric generating facilities which continue to be coal-fired have dry ash handling, and the ash ponds undergoing closure have a detailed dam safety inspection conducted at least quarterly. 

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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

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for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2011,2012, the federal government has not accepted any spent fuel from Summer Station Unit 1, or any other nuclear generating facility, 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 expects to be able to expand itshas commenced construction of a dry cask storage capacityfacility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1 through dry cask storage or1. 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. In addition, the state of South Carolina has a similar law. Consolidated SCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean up. In addition, regulators from the EPA and other federal or state agencies periodically notify Consolidated SCE&G that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in deferred debitsregulatory assets and amortized with recovery provided through rates. Consolidated SCE&G has assessed the following matters:

Electric Operations

SCE&G has been named, along with 53 others, by the EPA as a PRP at the AER Superfund site located in Augusta, Georgia. The PRPs funded a Remedial Investigation and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that was completed in 2010. A clean-up cost has been estimated and the PRPs have agreed to an allocation of those costs based primarily on volume and type of material each PRP sent to the site. SCE&G’s allocation did not have a material impact on its results of operations, cash flows or financial condition.

SCE&G maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. SCE&G defers site assessmentAmounts expected to be recovered through rates are recorded in regulatory assets and, cleanupif applicable, amortized over approved amortization periods.  At December 31, 2013, such regulatory assets totaled approximately $1.2 million. Other environmental costs and expectsare recorded to recover them through rates.

expense as incurred.

Gas Distribution

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC. SCE&G anticipates that major remediation activities at these sites will continue until 20142017 and will cost an additional $8.3$21.2 million. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates and insurance settlements.rates. At December 31, 2011,2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.9$36.7 million and are included in regulatory assets.


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REGULATORY MATTERS

SCE&G, GENCO and Fuel Company are subject to the regulatory jurisdiction of the following entities for the matters noted.
CompanyRegulatory Jurisdiction/Matters
SCE&G, GENCO and Fuel CompanyThe CFTC to the extent they transact swaps as defined in Dodd-Frank.
SCE&GThe SEC as to the issuance of certain securities and other matters; the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters; the FERC as to issuance of short-term borrowings, guarantees of short-term indebtedness, certain acquisitions and other matters; the PHMSA as to integrity management requirements for gas distribution pipeline systems; and the NRC with respect to the ownership, construction, operation and decommissioning of its currently operated and planned nuclear generating facilities. NRC jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety, antitrust considerations and environmental impact. In addition, the Federal Emergency Management Agency reviews, in conjunction with the NRC, certain aspects of emergency planning relating to the operation of nuclear plants.
SCE&G and GENCOThe FERC and DOE, under the Federal Power Act, as to the transmission of electric energy in interstate commerce, the sale of electric energy at wholesale for resale, the licensing of hydroelectric projects and certain other matters, including accounting.
GENCOThe SCPSC as to the issuance of securities (other than short-term borrowings) and the FERC as to the issuance of short-term borrowings, accounting, certain acquisitions and other matters.
Fuel CompanyThe SEC as to the issuance of certain securities.

Material retail rate proceedings are described in more detail in Note 2 to the consolidated financial statements.

SCE&G is subject to In addition, the jurisdiction of the SEC as to the issuance of certain securities and other matters; the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters; and FERC as to issuance of short-term borrowings, certain acquisitions and other matters.

GENCO is subject to the jurisdiction of the SCPSC as to issuance of securities (other than short-term borrowings) and is subject to the jurisdiction of FERC as to issuance of short-term borrowings, accounting, certain acquisitions and other matters.

SCE&G and GENCO are subject to regulation under the Federal Power Act, administered by FERC and DOE, in the transmission of electric energy in interstate commerce and in the sale of electric energy at wholesale for resale, as well as with respect to licensed hydroelectric projects and certain other matters, including accounting.

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The RSA allows natural gas distribution companies in South Carolina to request annual adjustments to rates to reflect changes in revenues and expenses and changes in investment. Such annual adjustments are subject to certain qualifying criteria and review by the SCPSC.

Effective February 12, 2010, the PHMSA issued a final rule establishing integrity management requirements for gas distribution pipeline systems. SCE&G has developed a plan and procedures to ensure that it will be fully compliant with this rule. SCE&G believes that any additional costs incurred to comply with the rule will be recoverable through rates.


CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Following are descriptions of Consolidated SCE&G’s accounting policies and estimates which are most critical in terms of reporting financial condition or results of operations.

Utility Regulation

Consolidated SCE&G’s regulated operations record certain assets and liabilities that defer the recognition of expenses and revenues to future periods in accordance with accounting guidance for rate-regulated utilities. In the future, in the event of deregulation or other changes in the regulatory environment, Consolidated SCE&G may no longer meet the criteria of accounting for rate-regulated utilities, and could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on the results of operations, liquidity or financial position of Consolidated SCE&G’s Electric DistributionOperations and Gas Distribution segments in the period the write-off would be recorded. See Note 2 to the consolidated financial statements for a description of Consolidated SCE&G’s regulatory assets and liabilities, including those associated with Consolidated SCE&G’s environmental assessment program.

Consolidated SCE&G’s generation assets would be exposed to considerable financial risks in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, Consolidated SCE&G could be required to write down its investment in those assets. Consolidated SCE&G cannot predict whether any write-downs would be necessary and, if they were, the extent to which they would affect Consolidated SCE&G’s results of operations in the period in which they would be recorded. As of December 31, 2011,2013, Consolidated SCE&G’s net investments in fossil/hydro and nuclear generation assets were $3.1$2.4 billion and $1.8$2.9 billion, respectively.


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Revenue Recognition and Unbilled Revenues

Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, SCE&G records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to customers for which they have not yet been billed. Such unbilled revenues reflect consideration of estimated usage by customer class, the effects of different rate schedules changes in weather and, where applicable, the impact of weather normalization provisions of rate structures. The accrual of unbilled revenues in this manner properly matches revenues and related costs. As of December 31, 20112013 and 2010,2012, accounts receivable included unbilled revenues of $117.8$111.9 million and $123.4$129.0 million, respectively, compared to total revenues of $2.8 billion for each of such years.

Nuclear Decommissioning

Accounting for decommissioning costs for nuclear power plants involves significant estimates related to costs to be incurred many years ininto the future. Among the factors that could change SCE&G’s accounting estimates related to decommissioning costs are changes in technology, changes in regulatory and environmental remediation requirements, and changes in financial assumptions such as discount rates and timing of cash flows. Changes in any of these estimates could significantly impact SCE&G’s financial position and cash flows (although changes in such estimates should be earnings-neutral, because these costs are expected to be collected from ratepayers).

Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, including both the cost of decommissioning plant components that are and are not subject to radioactive contamination, totals $451.0$696.8 million, stated in 20062012 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station Unit 1. The cost estimate assumes that upon closure the site would be maintained over a period offor 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use.

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Under SCE&G’s method of funding decommissioning costs, amounts collected through rates are invested in insurance policies on the lives of certain Company personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.

Accounting for Pensions and Other Postretirement Benefits

SCANA recognizes the overfunded or underfunded status of its defined benefit pension plan as an asset or liability in its balance sheet and changes in funded status as a component of net periodic benefit cost or other comprehensive income, net of tax, or as a regulatory asset as required by accounting guidance. SCANA’s plan is adequately funded under current regulations. Accounting guidance requires the use of several assumptions, the selection of which may have a large impact on the resulting pension cost or income recorded. Among the more sensitive assumptions are those surrounding discount rates and expected returns on assets. Net pension cost of $17.3 million ($13.9 million attributable to SCE&G) recorded in 2011 reflects the use of a 5.56% discount rate, derived using a cash flow matching technique, and an assumed 8.25% long-term rate of return on plan assets. SCANA believes that these assumptions were, and that the resulting pension income amount was, reasonable. For purposes of comparison, using a discount rate of 5.31% in 2011 would have increased SCANA’s pension cost by $1.3 million. Had the assumed long-term rate of return on assets been 8.00%, SCANA’s pension cost for 2011 would have increased by $1.9 million.

Due to turmoil in the financial markets and the resultant declines in plan asset values in the fourth quarter of 2008, SCE&G recorded significant amounts of pension cost in 2009, 2010 and 2011 compared to the pension income recorded previously. However, in February 2009, SCE&G was granted accounting orders by the SCPSC which allowed it to mitigate a significant portion of this increased pension cost by deferring as a regulatory asset the amount of pension expense above the level that was included in then current cost of service rates for its retail electric and gas distribution regulated operations. In July 2010, upon the new retail electric base rates becoming effective, SCE&G began deferring as a regulatory asset all pension cost related to its regulated retail electric operations that otherwise would have been charged to expense. In November 2010, upon the updated gas rates becoming effective under the RSA, SCE&G began deferring as a regulatory asset, all pension cost related to its regulated natural gas operations that otherwise would have been charged to expense.

The pension trust is adequately funded under current regulations, and no contributions have been required since 1997. Management does not anticipate the need to make significant pension contributions until after 2012.

SCANA accounts for the cost of its postretirement medical and life insurance benefit plans in a similar manner to that used for its defined benefit pension plan. This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. SCANA used a discount rate of 5.72%, derived using a cash flow matching technique, and recorded a net cost to SCE&G of $14.0 million for 2011. Had the selected discount rate been 5.47% (25 basis points lower than the discount rate referenced above), the expense for 2011 would have been $0.4 million higher. Because the plan provisions include “caps” on company per capita costs, healthcare cost inflation rate assumptions do not materially impact the net expense recorded.


Asset Retirement Obligations

Consolidated SCE&G accrues for the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation in accordance with applicable accounting guidance. The obligations are recognized at fairpresent value in the period in which they are incurred and associated asset retirement costs are capitalized as a part of the carrying amount of the related long-lived assets. Because such obligations relate primarily to Consolidated SCE&G’s regulated utility operations, their recordingrecognition has no significant impact on results of operations. As of December 31, 2011,2013, Consolidated SCE&G has recorded AROs of $124$191 million for nuclear plant decommissioning (as discussed above) and $326AROs of $356 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded in accordance with the relevant accounting guidance are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments may be made many years in the future. Changes in these estimates will be recorded over time; however, these changes in estimates are not expected to materially impact results of operations so long as the regulatory framework for utilities remains in place.

OTHER MATTERS

Nuclear Generation

Accounting for Pensions and Other Postretirement Benefits
SCE&G participates in SCANA’s noncontributory defined benefit pension plan, which covers substantially all regular, full-time employees. SCANA recognizes the funded status of its defined benefit pension plan as an asset or liability and Santee Cooperchanges in funded status as a component of net periodic benefit cost or other comprehensive income, net of tax, or as a regulatory asset as required by accounting guidance. SCANA’s plan is adequately funded under current regulations. Accounting guidance requires the use of several assumptions, the selection of which has an impact on the resulting pension cost recorded. Among the more sensitive assumptions are partiesthose surrounding discount rates and expected returns on assets. SCANA's net pension cost of $31.7 million ($26.0 million attributable to constructionSCE&G) recorded in 2013 reflects the use of a 4.10% discount rate prior to re-measurement on September 1, 2013 and operating agreementsa 5.07% discount rate after the re-measurement, derived using a cash flow matching technique, and an assumed 8.00% long-term rate of return on plan assets. The re-measurement occurred in connection with a plan amendment and related curtailment, which they agreedis further described below. SCANA believes that these assumptions

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were, and that the resulting pension cost amount was, reasonable. For purposes of comparison, a 25 basis point reduction in the discount rate in 2013 would have increased SCANA’s pension cost by $1.2 million. Further, had the assumed long-term rate of return on assets been 7.75%, SCANA’s pension cost for 2013 would have increased by $1.9 million.

The following information with respect to pension assets (and returns thereon) should also be joint owners,noted.
SCANA determines the fair value of a large majority of its pension assets utilizing market quotes or derives them from modeling techniques that incorporate market data. Less than 10% of assets are valued using less transparent Level 3 methods.
In developing the expected long-term rate of return assumptions, SCANA evaluates historical performance, targeted allocation amounts and share operatingexpected payment terms. As of the beginning of 2013, the plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 7.5%, 6.3%, 8.8% and 9.7%, respectively. The 2013 expected long-term rate of return of 8.00% was based on a target asset allocation of 58% with equity managers, 33% with fixed income managers and 9% with hedge fund managers. SCANA regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. As of the beginning of 2014, the plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 6.4%, 6.0%, 8.3% and 9.3%, respectively. For 2014, the expected rate of return is 8.00%.
As of December 31, 2013, 2012, and 2011, approximately $5.5 million, $14.9 million and $9.0 million, respectively, of pension expense was deferred pursuant to regulatory orders. As part of a December 2012 SCPSC rate order, cumulative previously deferred pension costs related to electric operations of approximately $63 million is being amortized over approximately 30 years, and starting in January 2013 current pension expense for electric operations is being recovered through a pension cost rider. Similarly, in connection with the October 2013 RSA order, previously deferred pension cost related to gas operations of approximately $14 million is being amortized over approximately 14 years, and effective November 2013, SCE&G is recovering current pension expense related to gas operations through cost of service rates.
In the third quarter of 2013, the pension plan was amended such that pension benefits will no longer be offered to employees hired or rehired after December 31, 2013, and pension benefits for existing participants will no longer accrue for services performed or compensation earned after December 31, 2023. As a result, SCANA recorded a curtailment charge due to the accelerated amortization of prior service cost. Approximately $5.3 million of the curtailment charge was applicable to regulated operations and was deferred within regulatory assets. SCE&G is recovering such deferred amounts through existing regulatory orders.

The closure of the plan to entrants after December 31, 2013 and the cessation of benefit accruals in 2023 are expected to further lessen the significance of pension costs and generation output,the criticality of the related estimates to SCE&G's financial statements. Further, the pension trust is adequately funded under current regulations, and management does not anticipate the need to make significant pension contributions for the foreseeable future.

In addition to pension benefits, SCE&G participates in SCANA’s unfunded postretirement health care and life insurance programs which provide benefits to certain active and retired employees. SCANA accounts for the cost of postretirement medical and life insurance benefit plans in a similar manner to that used for its defined benefit pension plan. This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. SCANA used a discount rate of 4.19%, derived using a cash flow matching technique, and recorded a net cost to SCE&G of $16.5 million for 2013. Had the selected discount rate been 3.94% (25 basis points lower than the discount rate referenced above), the expense for 2013 would have been $0.5 million higher. Because the plan provisions include “caps” on company per capita costs, and because employees hired after December 31, 2010 are responsible for the full cost of retiree medical benefits elected by them, healthcare cost inflation rate assumptions do not materially impact the net expense recorded. 
NEW NUCLEAR CONSTRUCTION MATTERS

SCE&G is constructing two 1,117-MW1,250 MW (1,117 MW, net) nuclear generation units to be constructed at the

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site of Summer Station,Station. SCE&G will jointly own the New Units with Santee Cooper, and SCE&G will be responsible for 55 percent of the cost of and receiving 55 percent ofreceive the output andfrom the New Units in proportion to its share of ownership, with Santee Cooper responsible for and receiving the remaining 45 percent.share. SCE&G's current ownership share in the New Units is 55%. Under these agreements,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. Under the terms of this agreement, SCE&G will have the primary responsibility for oversight of the construction ofacquire a one percent ownership interest in the New Units at the commercial operation date of Unit 2, will acquire an additional two percent ownership interest no later than the first anniversary of such commercial operation date, and will be responsible foracquire the final two percent no later than the


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second anniversary of such commercial operation date. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units as they come online.

SCE&G, on behalf of itself and as agent for Santee Cooper, has entered into the EPC Contract with the Consortium for the design and construction ofto third parties until the New Units.Units are complete.


It is expected that Unit 2 will be placed in service in the fourth quarter of 2017 or the first quarter of 2018, with Unit 3's in-service date approximately 12 months later. SCE&G’s&G's share of the estimated cash outlays (future value, excluding AFC) for its current 55% ownership share totals approximately $6$5.4 billion for plant costs and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC.

As In addition, under the terms of the agreement previously reported,described, SCE&G has been advised byagreed to pay an amount equal to Santee Cooper that it is reviewing certain aspectsCooper's actual cost of its capital improvement program and long-term power supply plan, including the levelpercentage conveyed as of its participation inthe date of conveyance, which SCE&G estimates will be approximately $500 million for the entire 5% interest. This transaction will not affect the payment obligations between the parties during construction for the New Units. Santee Cooper has entered into a letterUnits, nor is it anticipated that the payments would be reflected in revised rates filings under the BLRA.


In November 2012, the SCPSC approved an updated construction schedule and additional updated capital costs of intent with Duke that may result$278 million (SCE&G's portion in Duke acquiring a2007 dollars). The November 2012 order approved additional identifiable capital costs of approximately $1 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications; approximately $8 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure; and approximately $132 million (SCE&G's portion in 2007 dollars) related to additional labor for the oversight of Santee Cooper’s ownership interest in the New Units.Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. In addition, the order approved revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims for costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict whether any change in Santee Cooper’s ownership interest or the additionoutcome of these appeals. For further discussion of new joint owners will increase project costs or delaynuclear construction matters, see Note 9.

The Consortium has experienced delays in the commercial operation datesschedule for fabrication and delivery of sub-modules for the New Units. Any such project cost increase or delay could be material.

The Consortium has recently performed an impact study, at SCE&G’s request, related to various costfabrication and timing alternatives arising from the delay in the issuance datedelivery of sub-modules are a focus area of the COL from mid-2011,Consortium, including sub-modules for module CA20, which wasis part of the date assumed whenauxiliary building, and CA01, which houses components inside the EPC Contract was signed in 2008,containment vessel. Modules CA20 and CA01 are considered critical path items for both New Units. All sub-modules for CA20 have been received on site and its fabrication is underway. CA20 is expected to be ready for placement on the early-2012 issuance date currently anticipated by SCE&G. The impact study analyzed three scenarios, including (1) compressing the construction schedule for the first New Unit but retaining the original substantial completion dates set forth in the EPC Contract, (2) extending the substantial completion date for the first New Unit to accommodate the COL delay, or (3) delaying the substantial completion datenuclear island of the first New Unit and acceleratingin the first quarter of 2014. In addition, the delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow it to be ready for placement on the nuclear island of the first New Unit during the third quarter of 2014. With this schedule, the Consortium continues to indicate that the substantial completion date forof the first New Unit is expected to be late 2017 or the first quarter of 2018 and that the substantial completion of the second New Unit is expected to be approximately twelve months after that of the first New Unit. The substantial completion dates currently approved by the SCPSC for the first and second New Units are March 15, 2017 and May 15, 2018, respectively. The SCPSC has also approved an 18-month contingency period beyond each of these dates. The preliminary expected new substantial completion dates are within the contingency periods. SCE&G cannot predict with certainty the extent to which the issue with the sub-modules or the delays in the substantial completion of the New Units will result in increased project costs. However, the preliminary estimate of the delay-related costs associated with SCE&G's 55% share of the New Units is approximately $200 million. SCE&G has recently informednot accepted responsibility for any of these delay-related costs and expects to have further discussions with the Consortium that it intendsregarding such responsibility. Additionally, the EPC Contract provides for liquidated damages in the event of a delay in the completion of the New Units, which will also be included in discussions with the Consortium. SCE&G believes its responsibility for any portion of the $200 million estimate should ultimately be substantially less, once all of the relevant factors are considered.


In addition to pursue scenario (3)the above-described project delays, SCE&G is also aware of financial difficulties at a supplier responsible for certain significant components of the project.  The Consortium is monitoring the potential for disruptions in such equipment fabrication and has also begun discussions concerningpossible responses.   Any disruptions could impact the update of cash flow forecastsproject's schedule or costs, and construction schedules on that basis.

such impacts could be material.


The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude. During the course of activities under the EPC Contract, issues have materialized that may impact project budget and schedule, including those relatedschedule. Claims specifically relating to COL delays, design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock conditions at the site. These issues havesite resulted in assertions of contractual entitlement to recover additional costs and may resultto be incurred. The resolution of these specific claims is discussed in requests for change orders fromNote 2 to the Consortium. While SCE&G has not accepted the validity of any claims, the total amount of the claims presented (SCE&G’s portion in 2007 dollars) is approximately $188 million.consolidated financial statements. SCE&G expects to resolve any such

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disputes that arise in the future, including any which may arise with respect to the delay-related costs discussed above, through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time, (see Note 2 to the consolidated financial statements), will be recoverable through rates.

On February 29, 2012, SCE&G filed


During the fourth quarter of 2013, the Consortium began a petition withfull re-baselining of the SCPSC seeking an order approvingUnit 2 and Unit 3 construction schedules to incorporate a further updated capital costmore detailed evaluation of the engineering and procurement activities necessary to accomplish the schedule 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 schedules, construction work crew assignments, and other items. The result will be a revised fully integrated construction schedule that incorporates additional identifiable capital costswill provide for detailed and itemized information on individual budget and cost categories, cost estimates at completion for all non-firm and fixed scopes of approximately $6 million (SCE&G’s portionwork, and the timing of specific construction activities and cash flow requirements. SCE&G anticipates that this revised schedule and the cost estimate at completion for all non-firm and fixed scopes of work will be finalized in 2007 dollars) relatedthe third quarter of 2014. SCE&G plans to reevaluate and reschedule its owners cost estimates and cash flow requirements in light of the new federal healthcare laws, information security measures and certain minor design modifications. That petition also includes increased capital costs of approximately $12 million (SCE&G’s portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 million (SCE&G’s portion in 2007 dollars) related to additional laborschedule.

When the NRC issued the COLs for the oversightNew Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units during constructionUnits' passive cooling system, and for preparingrequiring the development of strategies to operaterespond to extreme natural events resulting in the loss of power at the New Units, facilitiesUnits. In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation, as well as a request for information related to emergency plant staffing. These conditions and information technology systems requiredrequirements are responsive to support the New Units and their personnel. Future petitions would be filedNRC's Near-Term Task Force report titled “Recommendations for any costs arising fromEnhancing Reactor Safety in the resolution21st Century.” This report was prepared in the wake of the commercial claims discussed above.

Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11%. In September 2011, the SCPSC approved an increase of $52.8 million or 2.4% under the BLRA for the annual revised rates adjustment filing. The new retail electric rates were effective for bills rendered on and after October 30, 2011.

In March 2011 aearthquake-generated tsunami, resulting from a massive earthquakewhich severely damaged several nuclear generating units and their back-up cooling systems in Japan. TheSCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the disaster is being evaluated world-wide,construction and numerous politicaloperation of the New Units, and regulatory bodies, including those in the United States, are seeking to determine if additional safety measures should be required at existing nuclear facilities, as well as those planned for construction. In particular, on July 12, 2011, the NRC’s Near-Term Task Force issued a report titled “Recommendations for Enhancing Reactor Safety in the 21st Century,” which SCE&G, is evaluating.pursuant to the license condition, prepared and submitted an integrated response plan for the New Units to the NRC in August 2013. SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, noror how such initiatives would impact SCE&G’s&G's existing Summer Station or the licensing, construction or operation of the New Units.

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In December 2011,Subject to a national megawatt capacity limitation, the NRC granted final design certification to Westinghouse for the AP1000 nuclear reactor, which is the reactorelectricity to be used for the New Units. This certification is a necessary step before the NRC can issue a COL for the New Units. In October 2011, the NRC conducted a mandatory hearing regarding the issuance of a COL for the New Units. This hearing followed the August 2011 completion of the FSER, in which the NRC staff concluded there were no safety aspects that would preclude issuing the COL, and the April 2011 completion of the FEIS, in which the NRC and the USACE concluded there were no environmental impacts that would preclude issuing the COL.

Fuel Contract

On January 27, 2011, SCE&G, for itself and as agent for Santee Cooper, and Westinghouse entered into a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, Westinghouse will supply enriched nuclear fuel assemblies for Summer Station Unit 1 and the New Units. Westinghouse will be SCE&G’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements of Summer Station Unit 1 andproduced by the New Units through 2033.(advanced nuclear units, as defined) is expected to qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code. Following the pouring of safety-related concrete for each of the New Units’ reactor buildings (March 2013 for the first New Unit and November 2013 for the second New Unit), SCE&G is dependent upon Westinghousehas applied to the IRS for providing fuel assembliesits allocations of such national megawatt capacity limitation. The IRS will forward the applications to the DOE for appropriate certification. Under current provisions of the new AP1000 passive reactorsInternal Revenue Code and based on SCE&G's current 55% ownership and other assumptions regarding volumes of electricity to be generated by the New Units, the aggregate production tax credits for which SCE&G qualifies could exceed $1.3 billion over the eight year period following each of the New Units' in-service dates. In January 2014, SCE&G amended its application to include the additional 5% interest in the New Units in the current and anticipated future absence of other commercially viable sources. Westinghouse currently provides maintenance and engineering supportthat it expects to Summer Station Unit 1 under a services alliance arrangement, and SCE&G has also contracted for Westinghouse to provide similar support servicesacquire. Additional production tax credits related to the New Units upon their completion and commencement of commercial operation.

5% interest could total as much as $125 million.


OTHER MATTERS
Financial Regulatory Reform

In July 2010,

Dodd-Frank became law. This Act provides for substantial additional regulation of over-the-counter and security-based derivative instruments, among other things, and requires numerous rule-makings by the Commodity Futures Trading CommissionCFTC and the SEC to implement. Consolidated SCE&G has determined that it meets the end-user exception in Dodd-Frank, with the lowest level of required regulatory reporting burden imposed by this law. Consolidated SCE&G is currently complying with these enacted regulations and intends to comply with regulations enacted in the future, but cannot predict when the final regulations will be issued or what requirements they will impose.


Off-Balance Sheet Transactions

Consolidated SCE&G does not hold significant investments in unconsolidated special purpose entities. Consolidated SCE&G does not engage in off-balance sheet financing or similar transactions, although it is party to incidental operating leases in the normal course of business, generally for office space, furniture, vehicles, equipment and rail cars, none of which are considered significant.



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Claims and Litigation

For a description of claims and litigation see Item 3. LEGAL PROCEEDINGS and Note 10 to the consolidated financial statements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

All financial instruments held by Consolidated SCE&G described below are held for purposes other than trading.

The tables below provide information about long-term debt issued by Consolidated SCE&G which is sensitive to changes in interest rates. For debt obligations, the tables present principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the figures shown reflect notional amounts, weighted average rates and related maturities. Fair values for debt represent quoted market prices. Interest rate swap agreements are valued using discounted cash flow models with independently sourced data.

 

 

Expected Maturity Date

 

December 31, 2011
Millions of dollars

 

2012

 

2013

 

2014

 

2015

 

2016

 

Thereafter

 

Total

 

Fair
Value

 

Long-Term Debt:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed Rate ($)

 

13.3

 

158.2

 

43.7

 

7.3

 

7.2

 

2,940.0

 

3,169.7

 

3,857.9

 

Average Interest Rate (%)

 

4.82

 

7.02

 

4.95

 

5.51

 

5.55

 

5.81

 

5.86

 

 

Variable Rate ($)

 

 

 

 

 

 

68.3

 

68.3

 

68.3

 

Average Variable Interest Rate (%)

 

 

 

 

 

 

.16

 

.16

 

 

Interest Rate Swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pay Fixed/Receive Variable ($)

 

250.0

 

150.0

 

 

 

 

71.4

 

471.4

 

(75.6

)

Average Pay Interest Rate (%)

 

2.60

 

4.89

 

 

 

 

3.29

 

3.43

 

 

Average Receive Interest Rate (%)

 

.58

 

.58

 

 

 

 

.11

 

.51

 

 

 

 

Expected Maturity Date

 

December 31, 2010
Millions of dollars

 

2011

 

2012

 

2013

 

2014

 

2015

 

Thereafter

 

Total

 

Fair
Value

 

Long-Term Debt:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed Rate ($)

 

166.5

 

12.0

 

157.3

 

42.7

 

6.7

 

2,596.0

 

2,981.2

 

3,243.3

 

Average Interest Rate (%)

 

6.66

 

4.78

 

7.04

 

4.96

 

5.49

 

5.89

 

5.97

 

 

Variable Rate ($)

 

 

 

 

 

 

71.4

 

71.4

 

71.4

 

Average Variable Interest Rate (%)

 

 

 

 

 

 

.40

 

.40

 

 

Interest Rate Swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pay Fixed/Receive Variable ($)

 

350.0

 

 

 

 

 

71.4

 

421.4

 

(30.8

)

Average Pay Interest Rate (%)

 

4.73

 

 

 

 

 

3.29

 

4.48

 

 

Average Receive Interest Rate (%)

 

.30

 

 

 

 

 

.30

 

.30

 

 

  Expected Maturity Date
December 31, 2013
Millions of dollars
 2014 2015 2016 2017 2018 Thereafter Total 
Fair
Value
Long-Term Debt:  
  
  
  
  
  
  
  
Fixed Rate ($) 45.2
 9.2
 108.6
 8.2
 717.9
 3,086.5
 3,975.6
 4,356.6
Average Interest Rate (%) 4.84
 4.73
 1.11
 4.96
 5.95
 6.62
 6.32
 
Variable Rate ($) 
 
 
 
 
 67.8
 67.8
 64.9
Average Variable Interest Rate (%) 
 
 
 
 
 0.11
 0.11
 
Interest Rate Swaps:  
  
  
  
        
Pay Fixed/Receive Variable ($) 600.0
 650.0
 
 
 
 71.4
 1,321.4
 30.6
Average Pay Interest Rate (%) 3.96
 4.16
 
 
 
 3.29
 4.02
 
Average Receive Interest Rate (%) 0.25
 0.25
 
 
 
 0.06
 0.24
 
  Expected Maturity Date
December 31, 2012
Millions of dollars
 2013 2014 2015 2016 2017 Thereafter Total 
Fair
Value
Long-Term Debt:  
  
  
  
  
  
  
  
Fixed Rate ($) 159.5
 45.1
 8.6
 8.1
 7.7
 3,405.9
 3,634.9
 4,458.0
Average Interest Rate (%) 6.98
 4.84
 4.85
 5.01
 5.12
 5.60
 5.65
 
Variable Rate ($) 
 
 
 
 
 67.8
 67.8
 65.8
Average Variable Interest Rate (%) 
 
 
 
 
 0.17
 0.17
 
Interest Rate Swaps:  
  
  
  
        
Pay Fixed/Receive Variable ($) 600.0
 300.0
 
 
 
 71.4
 971.4
 (2.5)
Average Pay Interest Rate (%) 3.01
 2.48
 
 
 
 3.29
 2.87
 
Average Receive Interest Rate (%) 0.31
 0.31
 
 
 
 0.13
 0.29
 
While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur.

The above tables exclude long-term debt of $15$3 million at December 31, 20112013 and $21$9 million at December 31, 2010,2012, which amounts do not have stated interest rates associated with them.


For further discussion of Consolidated SCE&G’s long-term debt and interest rate derivatives, see ITEMItem 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — LIQUIDITY AND CAPITAL RESOURCESLiquidity and alsoCapital Resources and Notes 4 and 6 of the condensed consolidated financial statements.

Commodity Price Risk

The following table provides information about SCE&G’s financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 DT. Fair value represents quoted market prices.

Expected Maturity:
Options

 

2012

 

2013

 

Purchased Call (Long):

 

 

 

 

 

Strike Price(a)

 

4.41

 

4.25

 

Contract Amount(b)

 

10.9

 

0.1

 

Fair Value(b)

 

0.1

 

 


(a)Weighted average, in dollars

(b)Millions of dollars

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Table of Contents

SCE&G uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 6 to the consolidated financial statements.

SCE&G’s tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of hedging activities are to be included in the PGA. As such, costs of related derivatives utilized by SCE&G to hedge gas purchasing activities are recoverable through weighted average cost of gas calculations. The offset to the change in fair value of these derivatives is deferred.

108





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Table of Contents

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

South Carolina Electric & Gas Company

Cayce, South Carolina


We have audited the accompanying consolidated balance sheets of South Carolina Electric & Gas Company and affiliates (the “Company”"Company") as of December 31, 20112013 and 2010,2012, and the related consolidated statements of income, comprehensive income, cash flows, and changes in equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2011.2013. Our audits also included the financial statement schedule listed in Part IV at Item 15. These financial statements and the financial statement schedule are the responsibility of the Company’sCompany's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.


We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’sCompany's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.


In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20112013 and 2010,2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011,2013, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.


/s/DELOITTE & TOUCHE LLP

Charlotte, North Carolina

February 29, 2012

10928, 2014



112




SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED BALANCE SHEETS
December 31, (Millions of dollars) 2013 2012
Assets  
  
Utility Plant In Service $10,378
 $10,096
Accumulated Depreciation and Amortization (3,499) (3,322)
Construction Work in Progress 2,682
 2,073
Plant to be Retired, Net 177
 362
Nuclear Fuel, Net of Accumulated Amortization 310
 166
Utility Plant, Net ($720 and $640 related to VIEs) 10,048
 9,375
Nonutility Property and Investments:  
  
Nonutility property, net of accumulated depreciation 69
 57
Assets held in trust, net-nuclear decommissioning 101
 94
Other investments 3
 3
Nonutility Property and Investments, Net 173
 154
Current Assets:  
  
Cash and cash equivalents 92
 51
Receivables, net of allowance for uncollectible accounts of $3 and $3 486
 483
Receivables-affiliated companies 19
 2
Inventories:  
  
Fuel 131
 203
Materials and supplies 120
 126
Emission allowances 1
 1
Prepayments and other 80
 143
Total Current Assets ($147 and $206 related to VIEs) 929
 1,009
Deferred Debits and Other Assets:  
  
Pension asset 96
 
Regulatory assets 1,303
 1,377
Other 151
 189
Total Deferred Debits and Other Assets ($35 and $54 related to VIEs) 1,550
 1,566
Total $12,700
 $12,104
See Notes to Consolidated Financial Statements.

113



December 31, (Millions of dollars) 2013 2012
Capitalization and Liabilities  
  
Common equity $4,372
 $3,929
Noncontrolling interest 117
 114
Total Equity 4,489
 4,043
Long-Term Debt, net 4,007
 3,557
Total Capitalization 8,496
 7,600
Current Liabilities:  
  
Short-term borrowings 251
 449
Current portion of long-term debt 48
 165
Accounts payable 241
 281
Affiliated payables 117
 124
Customer deposits and customer prepayments 56
 51
Taxes accrued 223
 151
Interest accrued 64
 63
Dividends declared 62
 46
Derivative financial instruments 1
 66
Other 71
 50
Total Current Liabilities 1,134
 1,446
Deferred Credits and Other Liabilities:  
  
Deferred income taxes, net 1,509
 1,479
Deferred investment tax credits 32
 36
Asset retirement obligations 547
 535
Postretirement benefits 173
 254
Regulatory liabilities 732
 665
Other 77
 89
Total Deferred Credits and Other Liabilities 3,070
 3,058
Commitments and Contingencies (Note 10) 
 
Total $12,700
 $12,104
See Notes to Consolidated Financial Statements.

114



SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, (Millions of dollars) 2013 2012 2011
Operating Revenues:  
  
  
Electric $2,431
 $2,453
 $2,432
Gas 414
 356
 387
Total Operating Revenues 2,845
 2,809
 2,819
Operating Expenses:  
  
  
Fuel used in electric generation 751
 844
 922
Purchased power 43
 28
 19
Gas purchased for resale 244
 197
 240
Other operation and maintenance 557
 542
 515
Depreciation and amortization 313
 293
 286
Other taxes 200
 188
 183
Total Operating Expenses 2,108
 2,092
 2,165
Operating Income 737
 717
 654
Other Income (Expense):  
  
  
Other income 53
 
 5
Other expenses (18) (18) (12)
Interest charges, net of allowance for borrowed funds used during construction of $13, $11 and $7 (217) (211) (204)
Allowance for equity funds used during construction 25
 21
 13
Total Other Expense (157) (208) (198)
Income Before Income Tax Expense 580
 509
 456
Income Tax Expense 189
 157
 140
Net Income 391
 352
 316
Less Net Income Attributable to Noncontrolling Interest 11
 11
 10
Earnings Available to Common Shareholder $380
 $341
 $306
See Notes to Consolidated Financial Statements.


115



SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

        
Years Ended December 31, (Millions of dollars) 2013 2012 2011 
        
Net Income $391
 $352
 $316
 
Other Comprehensive Income (Loss), net of tax:       
Deferred costs of employee benefit plans, net of tax $-, $- and $- 1
 (1) (1) 
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax $-, $- and $- 
 
 
 
Other Comprehensive Income (Loss) 1
 (1) (1) 
Total Comprehensive Income 392
 351
 315
 
Less comprehensive income attributable to noncontrolling interest (11) (11) (10) 
Comprehensive income available to common shareholder $381
 $340
 $305
 
        

See Notes to Consolidated Financial Statement

116

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED BALANCE SHEETS

December 31, (Millions of dollars)

 

2011

 

2010

 

Assets

 

 

 

 

 

Utility Plant In Service:

 

$

10,312

 

$

10,112

 

Accumulated Depreciation and Amortization

 

(3,367

)

(3,098

)

Construction Work in Progress

 

1,472

 

1,051

 

Nuclear Fuel, Net of Accumulated Amortization

 

171

 

133

 

Utility Plant, Net ($662 and $634 related to VIEs)

 

8,588

 

8,198

 

Nonutility Property and Investments:

 

 

 

 

 

Nonutility property, net of accumulated depreciation

 

52

 

46

 

Assets held in trust, net-nuclear decommissioning

 

84

 

76

 

Other investments

 

2

 

4

 

Nonutility Property and Investments, Net

 

138

 

126

 

Current Assets:

 

 

 

 

 

Cash and cash equivalents

 

16

 

31

 

Receivables, net of allowance for uncollectible accounts of $3 and $3

 

482

 

507

 

Receivables-affiliated companies

 

9

 

 

Inventories (at average cost):

 

 

 

 

 

Fuel

 

196

 

216

 

Materials and supplies

 

120

 

117

 

Emission allowances

 

2

 

6

 

Prepayments and other

 

82

 

168

 

Deferred income taxes

 

8

 

15

 

Total Current Assets ($193 and $221 related to VIEs)

 

915

 

1,060

 

Deferred Debits and Other Assets:

 

 

 

 

 

Pension asset

 

 

57

 

Regulatory assets

 

1,206

 

996

 

Other

 

190

 

137

 

Total Deferred Debits and Other Assets ($61 and $43 related to VIEs)

 

1,396

 

1,190

 

Total

 

$

11,037

 

$

10,574

 

STATEMENTS OF CASH FLOWS

For the Years Ended December 31, (Millions of dollars) 2013 2012 2011
Cash Flows From Operating Activities:  
  
  
Net income $391
 $352
 $316
Adjustments to reconcile net income to net cash provided from operating activities:  
  
  
Losses from equity method investments 3
 4
 2
Deferred income taxes, net 29
 116
 138
Depreciation and amortization 315
 294
 288
Amortization of nuclear fuel 57
 44
 40
Allowance for equity funds used during construction (25) (21) (13)
Carrying cost recovery (3) 
 
Changes in certain assets and liabilities:  
  
  
Receivables (36) 35
 (31)
Inventories 35
 (60) (25)
Prepayments (17) (64) 82
Regulatory assets 83
 (158) (165)
Other regulatory liabilities 54
 64
 (12)
Accounts payable 5
 27
 (48)
Taxes accrued 72
 1
 13
Interest accrued 1
 9
 4
Pension and other postretirement benefits (186) 69
 70
    Other assets 52
 (84) 27
    Other liabilities 22
 46
 (31)
Net Cash Provided From Operating Activities 852
 674
 655
Cash Flows From Investing Activities:  
  
  
Property additions and construction expenditures (1,003) (978) (786)
Proceeds from investments and sales of assets (including derivative collateral posted) 144
 275
 11
Purchase of investments (including derivative collateral posted) (116) (268) (57)
Payments upon interest rate derivative contract settlement (49) 
 (31)
  Proceeds from interest rate derivative contract settlement 163
 14
 
Net Cash Used For Investing Activities (861) (957) (863)
Cash Flows From Financing Activities:  
  
  
Proceeds from issuance of long-term debt 451
 513
 379
Contribution from parent 311
 128
 107
Repayment of long-term debt (251) (49) (206)
Dividends (241) (202) (205)
Short-term borrowings-affiliate, net (22) (9) (13)
Short-term borrowings, net (198) (63) 131
Net Cash Provided From Financing Activities 50
 318
 193
Net Increase (Decrease) in Cash and Cash Equivalents 41
 35
 (15)
Cash and Cash Equivalents, January 1 51
 16
 31
Cash and Cash Equivalents, December 31 $92
 $51
 $16
Supplemental Cash Flow Information:  
  
  
Cash paid for—Interest (net of capitalized interest of $13, $11 and $7) $200
 $186
 $181
                      —Income taxes 92
 105
 
Noncash Investing and Financing Activities:  
  
  
Accrued construction expenditures 100
 116
 75
Capital lease 4
 8
 6
Nuclear fuel purchase 98
 
 
See Notes to Consolidated Financial Statements.

110


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December 31, (Millions of dollars)

 

2011

 

2010

 

Capitalization and Liabilities

 

 

 

 

 

Common equity

 

$

3,665

 

$

3,437

 

Noncontrolling interest

 

108

 

104

 

Total Equity

 

3,773

 

3,541

 

Long-Term Debt, net

 

3,222

 

3,037

 

Total Capitalization

 

6,995

 

6,578

 

Current Liabilities:

 

 

 

 

 

Short-term borrowings

 

512

 

381

 

Current portion of long-term debt

 

19

 

22

 

Accounts payable

 

231

 

341

 

Affiliated payables

 

136

 

140

 

Customer deposits and customer prepayments

 

54

 

60

 

Taxes accrued

 

150

 

137

 

Interest accrued

 

54

 

50

 

Dividends declared

 

39

 

54

 

Derivative liabilities

 

2

 

34

 

Other

 

61

 

80

 

Total Current Liabilities

 

1,258

 

1,299

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

Deferred income taxes, net

 

1,371

 

1,240

 

Deferred investment tax credits

 

40

 

56

 

Asset retirement obligations

 

449

 

478

 

Pension and other postretirement benefits

 

179

 

163

 

Regulatory liabilities

 

575

 

662

 

Other

 

170

 

98

 

Total Deferred Credits and Other Liabilities

 

2,784

 

2,697

 

Commitments and Contingencies (Note 10)

 

 

 

Total

 

$

11,037

 

$

10,574

 

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
  Common Stock Retained 
Accumulated
Other
Comprehensive
 Noncontrolling Total
Millions Shares Amount Earnings Income (Loss) Interest Equity
Balance at January 1, 2011 40
 $1,934
 $1,505
 $(2) $104
 $3,541
Earnings available for common shareholder  
  
 306
  
 10
 316
Deferred cost of employee benefit plans, net of tax $-  
  
  
 (1)  
 (1)
Total Comprehensive Income (Loss)     306
 (1) 10
 315
Capital contributions from parent  
 107
  
  
  
 107
Cash dividends declared  
  
 (184)  
 (6) (190)
Balance at December 31, 2011 40
 2,041
 1,627
 (3) 108
 3,773
Earnings Available for Common Shareholder  
  
 341
  
 11
 352
Deferred Cost of Employee Benefit Plans, net of tax $-  
  
  
 (1)  
 (1)
Total Comprehensive Income (Loss)     341
 (1) 11
 351
Capital contributions from parent  
 126
  
  
 2
 128
Cash dividends declared  
  
 (202)  
 (7) (209)
Balance at December 31, 2012 40
 2,167
 1,766
 (4) 114
 4,043
Earnings Available for Common Shareholder  
  
 380
  
 11
 391
Deferred Cost of Employee Benefit Plans, net of tax $-  
  
  
 1
  
 1
Total Comprehensive Income     380
 1
 11
 392
Capital contributions from parent  
 312
  
  
 (1) 311
Cash dividends declared  
  
 (250)  
 (7) (257)
Balance at December 31, 2013 40
 $2,479
 $1,896
 $(3) $117
 $4,489
See Notes to Consolidated Financial Statements.

111



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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, (Millions of dollars)

 

2011

 

2010

 

2009

 

Operating Revenues:

 

 

 

 

 

 

 

Electric

 

$

2,432

 

$

2,374

 

$

2,149

 

Gas

 

387

 

441

 

420

 

Total Operating Revenues

 

2,819

 

2,815

 

2,569

 

Operating Expenses:

 

 

 

 

 

 

 

Fuel used in electric generation

 

922

 

947

 

822

 

Purchased power

 

19

 

17

 

17

 

Gas purchased for resale

 

240

 

287

 

276

 

Other operation and maintenance

 

515

 

514

 

490

 

Depreciation and amortization

 

286

 

271

 

255

 

Other taxes

 

183

 

175

 

162

 

Total Operating Expenses

 

2,165

 

2,211

 

2,022

 

Operating Income

 

654

 

604

 

547

 

Other Income (Expense):

 

 

 

 

 

 

 

Other income

 

5

 

12

 

28

 

Other expenses

 

(12

)

(15

)

(11

)

Interest charges, net of allowance for borrowed funds used during construction of $7, $10 and $22

 

(204

)

(186

)

(164

)

Allowance for equity funds used during construction

 

13

 

19

 

28

 

Total Other Expense

 

(198

)

(170

)

(119

)

Income Before Income Tax Expense

 

456

 

434

 

428

 

Income Tax Expense

 

140

 

130

 

140

 

Net Income

 

316

 

304

 

288

 

Less Net Income Attributable to Noncontrolling Interest

 

10

 

14

 

7

 

Net Income Attributable to SCE&G

 

306

 

290

 

281

 

Preferred Stock Cash Dividends Declared

 

 

 

(9

)

Earnings Available to Common Shareholder

 

$

306

 

$

290

 

$

272

 

Dividends Declared on Common Stock

 

$

189

 

$

199

 

$

179

 

See Notes to Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, (Millions of dollars)

 

2011

 

2010

 

2009

 

Cash Flows From Operating Activities:

 

 

 

 

 

 

 

Net income

 

$

316

 

$

304

 

$

288

 

Adjustments to reconcile net income to net cash provided from operating activities:

 

 

 

 

 

 

 

Losses (earnings) from equity method investments

 

2

 

2

 

 

Deferred income taxes, net

 

138

 

234

 

74

 

Depreciation and amortization

 

288

 

276

 

266

 

Amortization of nuclear fuel

 

40

 

36

 

18

 

Allowance for equity funds used during construction

 

(13

)

(19

)

(28

)

Carrying cost recovery

 

 

(3

)

(5

)

Cash provided (used) by changes in certain assets and liabilities:

 

 

 

 

 

 

 

Receivables

 

(31

)

(110

)

91

 

Inventories

 

(25

)

(5

)

(144

)

Prepayments

 

82

 

(87

)

43

 

Regulatory assets

 

(165

)

(55

)

(84

)

Other regulatory liabilities

 

(12

)

(11

)

(2

)

Accounts payable

 

(48

)

59

 

(1

)

Taxes accrued

 

13

 

9

 

8

 

Interest accrued

 

4

 

(1

)

1

 

Changes in other assets

 

27

 

(78

)

(35

)

Changes in other liabilities

 

39

 

120

 

(54

)

Net Cash Provided From Operating Activities

 

655

 

671

 

436

 

Cash Flows From Investing Activities:

 

 

 

 

 

 

 

Property additions and construction expenditures

 

(786

)

(771

)

(751

)

Proceeds from investments and sales of assets (including derivative collateral posted)

 

11

 

49

 

27

 

Investment in affiliate

 

 

41

 

(23

)

Purchase of investments (including derivative collateral posted)

 

(57

)

(43

)

(6

)

Settlement of interest rate contracts

 

(31

)

 

 

Net Cash Used For Investing Activities

 

(863

)

(724

)

(753

)

Cash Flows From Financing Activities:

 

 

 

 

 

 

 

Proceeds from issuance of long-term debt

 

379

 

90

 

421

 

Contribution from parent

 

107

 

146

 

348

 

Repayment of long-term debt

 

(206

)

(219

)

(423

)

Redemption of preferred stock

 

 

 

(113

)

Dividends

 

(205

)

(195

)

(182

)

Short-term borrowings-affiliate, net

 

(13

)

1

 

61

 

Short-term borrowings, net

 

131

 

127

 

220

 

Net Cash Provided From (Used For) Financing Activities

 

193

 

(50

)

332

 

Net Increase (Decrease) in Cash and Cash Equivalents

 

(15

)

(103

)

15

 

Cash and Cash Equivalents, January 1

 

31

 

134

 

119

 

Cash and Cash Equivalents, December 31

 

$

16

 

$

31

 

$

134

 

Supplemental Cash Flow Information:

 

 

 

 

 

 

 

Cash paid for

-Interest (net of capitalized interest of $7, $9 and $22)

 

$

181

 

$

175

 

$

152

 

 

-Income taxes

 

 

31

 

61

 

Noncash Investing and Financing Activities:

 

 

 

 

 

 

 

Accrued construction expenditures

 

75

 

168

 

141

 

Capital lease

 

6

 

 

 

See Notes to Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND COMPREHENSIVE INCOME

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

 

 

 

 

Other

 

 

 

 

 

 

 

Common Stock

 

Retained

 

Comprehensive

 

Noncontrolling

 

Total

 

Millions

 

Shares

 

Amount

 

Earnings

 

Income (Loss)

 

Interest

 

Equity

 

Balance at January 1, 2009

 

40

 

$

1,440

 

$

1,310

 

$

(46

)

$

95

 

$

2,799

 

Comprehensive Income:

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings available for common shareholder

 

 

 

 

 

272

 

 

 

7

 

279

 

Deferred cost of employee benefit plans, net of tax $8

 

 

 

 

 

 

 

13

 

 

 

13

 

Total Comprehensive Income

 

 

 

 

 

272

 

13

 

7

 

292

 

Capital contributions from parent

 

 

 

348

 

 

 

 

 

 

 

348

 

Cash dividends declared

 

 

 

 

 

(175

)

 

 

(5

)

(180

)

Balance at December 31, 2009

 

40

 

$

1,788

 

$

1,407

 

$

(33

)

$

97

 

$

3,259

 

Comprehensive Income:

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings Available for Common Shareholder

 

 

 

 

 

290

 

 

 

14

 

304

 

Deferred Cost of Employee Benefit Plans, net of tax $19

 

 

 

 

 

 

 

31

 

 

 

31

 

Total Comprehensive Income

 

 

 

 

 

290

 

31

 

14

 

335

 

Capital contributions from parent

 

 

 

146

 

 

 

 

 

 

 

146

 

Cash dividends declared

 

 

 

 

 

(192

)

 

 

(7

)

(199

)

Balance at December 31, 2010

 

40

 

$

1,934

 

$

1,505

 

$

(2

)

$

104

 

$

3,541

 

Comprehensive Income (Loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings Available for Common Shareholder

 

 

 

 

 

306

 

 

 

10

 

316

 

Losses on Employee Benefit Plans, net of tax $-

 

 

 

 

 

 

 

(1

)

 

 

(1

)

Total Comprehensive Income (Loss)

 

 

 

 

 

306

 

(1

)

10

 

315

 

Capital contributions from parent

 

 

 

107

 

 

 

 

 

 

 

107

 

Cash dividends declared

 

 

 

 

 

(184

)

 

 

(6

)

(190

)

Balance at December 31, 2011

 

40

 

$

2,041

 

$

1,627

 

$

(3

)

$

108

 

$

3,773

 

See Notes to Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Principles of Consolidation

SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA, a South Carolina corporation. Consolidated SCE&G engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina.

The accompanying Consolidated Financial Statements reflect the accounts of SCE&G, Fuel Company and GENCO. Intercompany balances and transactions between SCE&G, Fuel Company and GENCO have been eliminated in consolidation.

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.

Intercompany balances and transactions between SCE&G, Fuel Company and GENCO have been eliminated in consolidation.

GENCO owns a coal-fired electric generating station with a 605 megawatt 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 $491 million)$476 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 and other environmental allowances. See also Note 4.

Use of Estimates

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

Utility Plant

Utility plant is stated substantially at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and an allowance for funds used during construction,AFC, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense.

AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. Consolidated SCE&G calculated AFC using average composite rates of 4.6%6.9% for 2011, 7.3%2013, 6.3% for 20102012 and 7.4%4.6% for 2009.2011. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.

Consolidated SCE&G records provisions for depreciation and amortization using the straight-line method based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were 2.90%2.94% in 2011, 2.84%2013, 2.91% in 20102012 and 2.95%2.90% in 2009.

Consolidated 2011.

SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in “Fuel used in electric generation” and recovered through the fuel cost component of retail electric rates. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the DOE under a contract for disposal of spent nuclear fuel.

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Jointly Owned Utility Plant

SCE&G jointly owns and is the operator of Summer Station Unit 1.  In addition, SCE&G will jointly own and will be the operator of the New Units being designed and constructed at the site of Summer Station.  Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership of a unit.  SCE&G’s share of the direct expenses areis included in the corresponding operating expenses on its income statement.

 

 

Unit 1

 

New Units

 

As of December 31, 2011

 

 

 

 

 

Percent owned

 

66.7

%

55.0

%

Plant in service

 

$

1.0 billion

 

 

Accumulated depreciation

 

$

545.0 million

 

 

Construction work in progress

 

$

71.0 million

 

$

1.2 billion

 

 

 

 

 

 

 

As of December 31, 2010

 

 

 

 

 

Percent owned

 

66.7

%

55.0

%

Plant in service

 

$

1.0 billion

 

 

Accumulated depreciation

 

$

548.8 million

 

 

Construction work in progress

 

$

40.1 million

 

$

891.2 million

 

As of December 31, 2013 2012
  Unit 1 New Units Unit 1 New Units
Percent owned 66.7% 55.0% 66.7% 55.0%
Plant in service $1.1 billion 
 $1.1 billion 
Accumulated depreciation $566.9 million 
 $557.0 million 
Construction work in progress $127.1 million $2.3 billion $113.6 million $1.8 billion
SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals approximately $6.0$5.4 billion for plant costs and for related transmission infrastructure costs, and is projected based on historical one-yearone-year and five year-year escalation rates as required by the SCPSC.

SCE&G’s latest Integrated Resource Plan filed with the SCPSC in February 2011 continues to support SCE&G’s need for 55 percent For a discussion of the output ofwhen the New Units.  As previously reported,Units are expected to be placed in service, and a description of SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation&G's agreement to acquire an additional 5% ownership in the New Units.  Santee Cooper has entered into a letter of intent with Duke that may result in Duke acquiring a portion of Santee Cooper’s ownership interest in the New Units.  SCE&G is unable to predict whether any change in Santee Cooper’s ownership interest or the addition of new joint owners will increase project costs or delay the commercial operation dates of the New Units.  Any such project cost increase or delay could be material.

The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude.  During the course of activities under the EPC Contract, issues have materialized that may impact project budget and schedule, including those related to COL delays, design modifications of the shield building and certain pre-fabricated modules for the New Units, and unanticipated rock conditions at the site.  These issues have resulted in assertions of contractual entitlement to recover additional costs and may result in requests for change orders from the Consortium.  While SCE&G has not accepted the validity of any claims, the total amount of the claims presented (SCE&G’s portion in 2007 dollars) is approximately $188 million.  SCE&G expects to resolve any such disputes through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time (seesee Note 2 to the consolidated financial statements), will be recoverable through rates.

10.

Included within receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for Summer Station Unit 1 and the New Units. These amounts totaled $63.6$75.6 million at December 31, 20112013 and $77.9$92.9 million at December 31, 2010.

2012.


Plant to be Retired

As previously disclosed, in 2012 SCE&G identified a total of six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. As of December 31, 2013, three of these units had been retired and their net carrying value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC.

Major Maintenance

Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections are classified as a regulatory asset or regulatory liability on the balance sheet (see Note 2). Other planned major maintenance is expensed when incurred.

Through 2017, SCE&G is authorized to collect $18.4$18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the yearyears ended December 31, 2011,2013 and 2012, SCE&G incurred $11.5$18.1 million and $11.1 million, respectively, for turbine maintenance. Cumulative costs for turbine maintenance in excess of cumulative collections are classified as a regulatory asset on the balance sheet.

Nuclear refueling outages are scheduled 18 months apart, and SCE&G begins accruing for each successive scheduled outage upon completion of the preceding scheduled outage.apart. SCE&G accrued $1.2$1.2 million per month from July 2008January 2010 through July 2011December 2012 for its portion of the outages in the spring of 2011 and the fall of 2009 and the spring of 2011.2012. Total costs for the 20092011 outage were

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$32.7 million,, of which SCE&G was responsible for $21.8 million.$22.7 million. Total costs for the 20112012 outage were $34.1$32.3 million, of which SCE&G was responsible for $22.7 million.$21.5 million. In July 2011,connection with the SCPSC's December 2012 approval of SCE&G's retail electric rates (see Note 2), effective January 1, 2013, SCE&G began accruing $1.2to accrue $1.4 million per month for its portion of the nuclear refueling planned foroutages that are scheduled to occur through the fallspring of 2012.  SCE&G had an accrued balance of $7.2 million at December 31, 2011 and $14.3 million at December 31, 2010.

2020.


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Nuclear Decommissioning

SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $451.0$696.8 million, stated in 2006 dollars.2012 dollars, pursuant an updated decommissioning cost study performed in 2012. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station Unit 1. The cost estimate assumes that the site wouldwill be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use.

Under SCE&G’s method of funding decommissioning costs, amounts collected through rates ($($3.2 million pre-tax in each of 2011, 20102013, 2012 and 2009)2011) are invested in insurance policies on the lives of certain SCE&G and affiliate personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Summer Station Unit 1 on an after-tax basis.

Cash and Cash Equivalents

Consolidated SCE&G considers temporary cash investments having original maturities of three months or less at time of purchase to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements and treasury bills and notes.

Accountbills.

Accounts Receivable

Accounts receivable reflect amounts due from customers arising from the delivery of energy or related services and include revenues earned pursuant to revenue recognition practices described below. These receivables include both billed and unbilled amounts. Receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis.


Inventory

Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas and fuel oil. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC. Emission allowances are included in inventory at average cost. Emission allowances are expensed at weighted average cost as used and recovered through fuel cost recovery rates approved by the SCPSC.
Income Taxes

Consolidated SCE&G is included in the consolidated federal income tax return of SCANA. Under a joint consolidated income tax allocation agreement, each SCANA subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers; otherwise, they are charged or credited to income tax expense. Also under provisions of the income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions.

Regulatory Assets and Regulatory Liabilities

Consolidated SCE&G records costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense or revenues would be recognized by a nonregulated enterprise. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the balance sheet as regulatory assets and regulatory liabilities (See(see Note 2). The regulatory assets and liabilities are amortized consistent with the treatment of the related costs in the ratemaking process.


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Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt

Consolidated SCE&G records long-term debt premium and discount within long-term debt and amortizes them as components of interest charges over the terms of the respective debt issues. Other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges.

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Environmental

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Environmental

SCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in deferred debitsregulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are recorded to expense.

expense as incurred.

Income Statement Presentation

In its consolidated statements of income, Consolidated SCE&G presents the activitiesrevenues and expenses of its regulated businessesactivities (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense).

Revenue Recognition

Consolidated SCE&G records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered but not yet billed. Unbilled revenues totaled $117.8$111.9 million at December 31, 20112013 and $123.4$129.0 million at December 31, 2010.

2012.

Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. This component is established by the SCPSC during annual fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during the next annual hearing.

subsequent hearings.

Customers subject to the PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. In addition, included in these deferred amounts are realized gains and losses incurred in SCE&G’s natural gas hedging program.


SCE&G’s gas rate schedules for residential, small commercial and small industrial customers include a WNA which minimizes fluctuations in gas revenues due to abnormal weather conditions. In August 2010, SCE&G implemented an eWNA on a one-year pilot basis for its electric customers, and it will continue on a pilot basis unless modified or terminatedcustomers; effective with the first billing cycle of 2014, the eWNA was discontinued as approved by the SCPSC.

See Note 2.

Taxes that are billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Accordingly, no suchSuch taxes are not included in revenues or expenses in the statements of income.

New Accounting Matter

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

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2.RATE AND OTHER REGULATORY MATTERS

Electric - Cost of Fuel
SCE&G

Electric

SCE&G’s&G's retail electric rates are established in part by usinginclude 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. EffectiveIn April 2012, the SCPSC approved SCE&G's request to decrease the total fuel cost component of its retail electric rates, and approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to recover an amount equal to its actual under-collected balance of base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a twelve month period beginning with the first billing cycle of May 2010,2012.


122




This April 2012 order was superseded, in part, by a December 2012 rate order in which the SCPSC approved a settlement agreement authorizingauthorized SCE&G to decreasereduce the fuel cost portion of its electric rates.  The settlement agreement incorporated SCE&G’s proposal to accelerate the recognition of $17.4 million of previously deferred state income tax credits and record an offsetting reduction to the recovery of fuel costs.  In addition, SCE&G agreed to defer recovery of its actual undercollected base fuel costs as of April 30, 2010 until May 2011.  SCE&G was allowed to charge and accrue carrying costs monthly on the actual base fuel costs undercollected balance as of the end of each month during this deferral period.  In February 2011, SCE&G requested authorization to increase the cost of fuel component of its retail electric rates and, in doing so, stated that SCE&G may not adjust its base fuel cost component prior to bethe last billing cycle of April 2014 except where necessary due to extraordinary unforeseen economic or financial conditions.  In February 2013, in connection with its annual review of base rates for fuel costs, SCE&G requested authorization to reduce its environmental fuel cost component effective with the first billing cycle of May 2011.  On2013.  Consistent with the December 2012 rate order,SCE&G did not request any adjustment to its base fuel cost component.  In March 17, 2011,2013, SCE&G, ORS and the SCEUC entered into a settlement agreement in which SCE&G agreed to recover its actual baseaccepting the proposed lower environmental fuel under-collected balance as of April 30, 2011 over a two-year period commencing with the first billing cycle of May 2011.  The settlement agreement also provided that SCE&G would be allowed to charge and accrue carrying costs monthly on the deferred balance.  By order dated April 26, 2011, the SCPSC approved the settlement agreement.  In February 2012, SCE&G requested authorization to decrease the cost of fuel component of its retail electric rates effective with the first billing cycle of May 2012.2013, and providing for the accrual of certain debt-related carrying costs on a portion of the under-collected balance of fuel costs. The nextSCPSC issued an order dated April 30, 2013, adopting and approving the settlement agreement and approving SCE&G's total fuel cost component. A public hearing for the annual hearing to review of base rates for fuel costs ishas been scheduled for March 22, 2012.

On July 15, 2010,April 3, 2014.


Pursuant to a November 2013 SCPSC accounting order, Consolidated SCE&G's electric revenue for 2013 was reduced for adjustments to the fuel cost component and related under-collected fuel balance of $41.6 million. Such adjustments are fully offset by the recognition within other income, also pursuant to that accounting order, of gains realized upon the 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. See also Note 6.

Electric - Base Rates

In October 2013, SCE&G received an accounting order from the SCPSC issued an order approvingdirecting 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 4.88%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 during 2013, $2.9 million of such carrying costs were accrued within other income. SCE&G anticipates that when the New Units are placed in service and accelerated tax deprecation is recognized on them, these deferred income tax assets will decline.  When these 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.

In December 2012, the SCPSC approved a 4.23% overall increase in SCE&G’s&G's retail electric base rates, effective January 1, 2013, and authorized an allowed return on common equity of 10.7%10.25%. AmongThe SCPSC also approved a mid-period reduction to the cost of fuel component in rates (as discussed above), a reduction in the DSM Programs component rider to retail rates, and the recovery of and a return on the net carrying value of certain retired generating plant assets described below. In February 2013, the SCPSC denied the SCEUC's petition for rehearing and the denial was not appealed.
The eWNA was designed to mitigate the effects of abnormal weather on residential and commercial customers' bills and had been in use since August 2010. In connection with the December 2012 order, SCE&G agreed to perform a study of alternative structures for eWNA. On November 1, 2013, the ORS filed a report with the SCPSC recommending that the eWNA be terminated with the last billing cycle for December 2013. On November 26, 2013, SCE&G, ORS and certain other parties filed a joint petition with the SCPSC requesting, among other things, that the SCPSC’s order (1) included implementationSCPSC discontinue the eWNA effective with bills rendered on or after the first billing cycle of January 2014. On December 20, 2013, the SCPSC granted the relief requested in the joint petition.

In connection with the above termination of the eWNA program effective December 31, 2013, electric revenues were reduced to reverse the prior accrual of an under-collected balance of $8.5 million. Pursuant to the SCPSC accounting order granting the above relief and terminating the eWNA, for such revenue reduction was fully offset by the recognition within other income of $8.5 million of gains realized upon the 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.

SCE&G’s&G files an IRP with the SCPSC annually which evaluates future electric customers, which begangeneration needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G's 2012 IRP identified six coal-fired units that SCE&G has subsequently retired or intends to retire by 2018, subject to future developments in Augustenvironmental regulations, among other matters. One of these units was retired in 2012, and two others were retired in the fourth quarter of 2013. The net carrying value of these retired units is recorded in regulatory assets as unrecovered plant and is being amortized over the units' previously estimated remaining useful lives as approved by the SCPSC. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. 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.

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In a July 2010 (2)order, the SCPSC provided for a $25$48.7 million credit, over one year, to SCE&G’s customers to be offset by amortization of weather-related revenues which were deferred in the first quarter of 2010 pursuant to a stipulation between SCE&G and the ORS, (3) provided for a $48.7 million credit to SCE&G’s&G's customers over two years to be offset by accelerated recognition of previously deferred state income tax credits. These tax credits and (4) provided for the recovery of certain federally-mandated capital expenditures that had been includedwere fully amortized in utility plant but were not being depreciated.

On July 15, 2010, the SCPSC issued an order approving the implementation by 2012.

SCE&G of certain&G's DSM Programs including the establishment offor electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and lost net margin revenue associated with the DSM Programs, along with an incentive for investing in such programs. The SCPSC’s order approved various settlement agreements among SCE&G the ORS and other intervening parties. On July 27, 2010, SCE&G filed the rate rider tariff sheet for DSM Programs with the SCPSC. The tariff rider was applied to bills rendered on or after October 30, 2010. The order requires that SCE&G submitsubmits annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC has approved the following rate changes pursuant to annual DSM Programs filings, which went into effect as indicated below:

YearEffectiveAmount
2013First billing cycle of May$16.9 million
2012First billing cycle of May$19.6 million
2011First billing cycle of June$7.0 million

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

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

In November 2013 the SCPSC approved SCE&G’s continued use of DSM programs for another six years, including approval of the rate rider mechanism and a revised portfolio of DSM programs.

In January 2011,2014 SCE&G submitted its annual DSM Programs filing to the SCPSC, its annual updatewhich included, among other things, a request to (1) recover one-half of the balance of allowable costs beginning with bills rendered on DSM Programs.  Included in the filing was a petition to update the rate rider to provide for the recovery of costs, lost net margin revenue, and the approved shared savings incentive for investing in such DSM Programs.  By order dated May 24, 2011, the SCPSC approved the updated rate rider and authorized SCE&G to increase its rates for DSM Programs as set forth in its petition.  The increase became effectiveafter the first billing cycle of June 2011.  In January 2012,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 recent settlement of certain interest rate derivative instruments to offset a portion of the net lost revenues component of SCE&G submitted&G’s DSM Programs rider, and (3) apply $5 million of its storm damage reserve and a portion of the gains from the recent settlement of certain interest rate derivative instruments, currently estimated to be $5.5 million, to the SCPSC its annual update on DSM programs.  Included inremaining balance of deferred net lost revenue as of April 30, 2014, deferred within regulatory assets resulting from the filing was a petition to update the rate rider to provide for the recovery of costs, lost net revenue, and the approved shared savings incentive for investing in such DSM Programs.

May 2013 order previously described.


Electric - BLRA


In January 2010,May 2011, the SCPSC approved SCE&G’s request for an order pursuant to the BLRA to approve an updated construction and capital cost schedule for the construction of two new nuclear generating units at Summer Station.  The updated schedule provides details of the construction and capital cost schedule beyond what was proposed and included in the original BLRA filing described below.

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

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In May 2009, two intervenors filed separate appeals of the SCPSC order with the South Carolina Supreme Court. With regard to the first appeal, which challenged the SCPSC’s prudency finding, the South Carolina Supreme Court issued an opinion on April 26, 2010, affirming the decision of the SCPSC. As for the second appeal, the South Carolina Supreme Court reversed the SCPSC’s decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G’s share of the project, as originally approved by the SCPSC, was $4.5 billion in 2007 dollars. Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court’s ruling, however, did not affect the project schedule or disturb the SCPSC’s issuance of a certificate of environmental compatibility and public convenience and necessity, which is required to construct the New Units. On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule sought by SCE&G that, reflected the removal of the contingency reserve andamong other matters, incorporated then identifiablethen-identifiable additional capital costs of $173.9$173.9 million (in (SCE&G's portion in 2007 dollars), and by order dated May 16, 2011,.


In November 2012, the SCPSC approved thean updated construction schedule and additional updated capital costs schedule as outlinedof $278 million (SCE&G's portion in the petition.

On February 29,2007 dollars). The November 2012 SCE&G filed a petition with the SCPSC seeking an order approving a further updated capital cost and construction schedule that incorporatesapproved additional identifiable capital costs of approximately $6$1 million (SCE&G’s&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications.  That petition also includes increased capital costs ofmodifications; approximately $12$8 million (SCE&G’s&G's portion in 2007 dollars) related to transmission infrastructure.  Finally, that petition includes amounts ofinfrastructure; and approximately $137$132 million (SCE&G’s&G's portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. Future petitions would be filedIn addition, the order approved revised substantial completion dates for any costs arising from the resolutionNew Units based on the March 30, 2012 issuance of the commercialCOL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims discussed in Note 1 to the consolidated financial statements (e.g., thosefor costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site).

site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals. For further discussion of new nuclear construction matters, see Note 9.

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&G's updated cost of debt and capital structure and on an allowed return on common equity of 11%11.0%. The SCPSC has

124



approved the following rate changes under the BLRA effective for bills rendered on and after October 30 in the following years:

Year

 

Increase

 

Amount

 

2011

 

2.4

%

$

52.8 million

 

2010

 

2.3

%

$

47.3 million

 

2009

 

1.1

%

$

22.5 million

 

Year Increase Amount
2013 2.90% $67.2 million
2012 2.30% $52.1 million
2011 2.40% $52.8 million
Gas

SCE&G

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

Year

 

Action

 

Amount

 

2011

 

2.1

%

Increase

 

$

8.6 million

 

2010

 

2.1

%

Decrease

 

$

10.4 million

 

2009

 

2.5

%

Increase

 

$

13.0 million

 

Year Action Amount
2013 No change  
2012 2.10% Increase $7.5 million
2011 2.10% Increase $8.6 million
SCE&G’s&G's natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred, including costs related to hedging natural gas purchasing activities.incurred. SCE&G’s&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month12-month rolling average. The annual PGA hearing to review SCE&G’saverage, and its gas purchasing policies and procedures was conducted in November 2011 beforepractices are reviewed annually by the SCPSC. The annual reviews conducted for each of the 12-month periods ended July 31, 2013 and 2012 resulted in the SCPSC issuedissuing an order in January 2012 finding that SCE&G’s&G's gas purchasing policies and practices during theeach review period of August 1, 2010 through July 31, 2011, were reasonable and prudent and authorized the suspension of SCE&G’s natural gas hedging program.

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Regulatory Assets and Regulatory Liabilities

Consolidated SCE&G’s&G has significant cost-based, rate-regulated utilities recognizeoperations and recognizes in theirits 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. SubstantiallyOther than unrecovered plant, substantially all of itsour regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.

 

 

December 31,

 

Millions of dollars

 

2011

 

2010

 

Regulatory Assets:

 

 

 

 

 

Accumulated deferred income taxes

 

$

238

 

$

205

 

Under-collections-electric fuel adjustment clause

 

28

 

25

 

Environmental remediation costs

 

25

 

27

 

AROs and related funding

 

301

 

284

 

Franchise agreements

 

40

 

45

 

Deferred employee benefit plan costs

 

348

 

288

 

Planned major maintenance

 

6

 

6

 

Deferred losses on interest rate derivatives

 

154

 

83

 

Deferred pollution control costs

 

25

 

13

 

Other

 

41

 

20

 

Total Regulatory Assets

 

$

1,206

 

$

996

 

Regulatory Liabilities:

 

 

 

 

 

Accumulated deferred income taxes

 

$

23

 

$

26

 

Asset removal costs

 

493

 

568

 

Storm damage reserve

 

32

 

38

 

Deferred gains on interest rate derivatives

 

24

 

26

 

Other

 

3

 

4

 

Total Regulatory Liabilities

 

$

575

 

$

662

 

  December 31,
Millions of dollars 2013 2012
Regulatory Assets:    
Accumulated deferred income taxes $256
 $248
Under-collections-electric fuel adjustment clause 18
 66
Environmental remediation costs 37
 39
AROs and related funding 350
 304
Franchise agreements 31
 36
Deferred employee benefit plan costs 215
 405
Planned major maintenance 
 6
Deferred losses on interest rate derivatives 124
 151
Deferred pollution control costs 37
 38
Unrecovered Plant 145
 20
DSM Programs 51
 27
Other 39
 37
Total Regulatory Assets $1,303
 $1,377

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Regulatory Liabilities:    
Accumulated deferred income taxes $19
 $21
Asset removal costs 495
 507
Storm damage reserve 27
 27
Deferred gains on interest rate derivatives 181
 110
Planned major maintenance 10
 
Total Regulatory Liabilities $732
 $665
Accumulated deferred income tax liabilities arisingthat 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


Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC during annual hearings which are expected to be recovered in retail electric rates in future periods.  These amounts are expected to be recovered in retail electric rates during the period January 2013 through April 2013.  SCE&G is allowed to recover interest on actual base fuel deferred balances through the recovery period.

over periods exceeding 12 months.


Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by SCE&G. These regulatory assets&G and are expected to be recovered over periods of up to approximately 2326 years.


ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station Unit 1 and conditional AROs.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 9590 years.


Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on ana SCPSC order, SCE&G began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years.


Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. A significant majorityIn connection with the December 2012 rate order, approximately $63 million of these deferred pension costs for electric operations are being recovered through utility rates over approximately 30 years. In connection with the October 2013 RSA order, approximately $14 million of deferred pension costs for gas operations are being recovered through utility rates over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 14 years, although recovery periods could become larger at the election of the SCPSC.

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Planned major maintenance related to certain fossil fuelfossil-fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders. SCE&G collected $8.5collects $18.4 million annually through July 15, 2010, through electric rates, to offset certain turbine maintenance expenditures. After July 15, 2010, SCE&G began collecting $18.4 million annually for this purpose. Nuclearsuch equipment maintenance. Through December 31, 2012, nuclear refueling charges arewere accrued during each 18-month18-month refueling outage cycle as a component of cost of service.

In connection with the December 2012 rate order, effective January 1, 2013, SCE&G collects and accrues $16.8 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 terminationsettlement of certain interest rate swapsderivatives designated as cash flow hedges. Thesehedges and (ii) the changes in fair value and payments received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years.

The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense 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 installation of scrubbers at Wateree and Williams Stations pursuant to specific regulatory orders. Such costs related to Williams Station amount to $9.4 million at December 31, 2011 and are being recovered through utility rates over approximately 30 years.  The remaining costs relateperiods up to Wateree Station, for which30 years.


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Unrecovered plant represents the Company will seek recovery in future proceedings before the SCPSC.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 allowedamortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives, or up to accrue interest onapproximately 14 years. Unamortized amounts are included in rate base and are earning a current return.

DSM Programs represents deferred costs relatedand certain unrecovered lost revenue associated with SCE&G’s Demand Side Management programs.  Deferred costs are currently being recovered over 5 years through a SCPSC approved rider.  Unrecovered lost revenue is to Wateree Station.

be recovered over periods not to exceed 24 months from date of deferral.  See Rate Matters - Electric Base Rates above for details regarding a 2014 filing with the SCPSC regarding recovery of these deferred costs and unrecovered lost revenue.


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 ofnon-legal obligation to remove assets in the future.


The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100$100 million, which can be applied to offset incremental storm damage costs in excess of $2.5$2.5 million in a calendar year, certain transmission and distribution insurance premiums and certain tree trimming and vegetation management expenditures in excess of amounts included in base rates. During the years ended December 31, 2011 and 2010,year. Pursuant to specific regulatory orders, SCE&G applied costs of $6.4 million and $9.5 million, respectively, to the reserve. Pursuant to SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&Ghas suspended collection of the storm damage reserve indefinitely pending future SCPSC action.

collection through rates indefinitely.


The SCPSC or the FERC havehas 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 thesesuch 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&G's results of operations, liquidity or financial position in the period the write-off would be recorded.


3.EQUITY


The balance for accumulated other comprehensive income (loss), net of tax, was as follows:
Millions of Dollars Deferred Employee Benefit Plans
Accumulated Other Comprehensive Loss as of January 1, 2012 $(3)
  Other comprehensive loss (1)
Accumulated Other Comprehensive Loss as of December 31, 2012 (4)
  Other comprehensive income 1
Accumulated Other Comprehensive Loss as of December 31, 2013 $(3)

Authorized shares of SCE&G common stock were 50 million as of December 31, 20112013 and 2010.2012.  Authorized shares of SCE&G preferred stock were 20 million none, of which 1,000 shares, no par value, were issued or outstanding,held by SCANA as of December 31, 20112013 and 2010.

2012.

SCE&G’s articles of incorporation do not limit the dividends that may be paid on its common stock. However, SCE&G’s bond indenture contains provisions that, under certain circumstances, which SCE&G considers to be remote, could limit the payment of cash dividends on its common stock.

With respect to hydroelectric projects, the

The Federal Power Act requires the appropriation of a portion of certain earnings therefrom.from hydroelectric projects. At December 31, 2011, $58.82013 and 2012, approximately $63.1 million and $61.0 million of retained earnings, respectively, were restricted by this requirement as to payment of cash dividends on common stock.

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4.LONG-TERM AND SHORT-TERM DEBT

Long-term debt by type with related weighted average interest rates and maturities at December 31 is as follows:

 

 

 

 

2011

 

2010

 

Dollars in millions

 

Maturity

 

Balance

 

Rate

 

Balance

 

Rate

 

First Mortgage Bonds (secured)

 

2013 - 2041

 

$

2,790

 

5.89

%

$

2,560

 

6.03

%

GENCO Notes (secured)

 

2012 - 2024

 

247

 

5.86

%

262

 

5.91

%

Industrial and Pollution Control Bonds(a)

 

2012 - 2038

 

194

 

4.48

%

228

 

4.63

%

Other

 

2012 - 2027

 

22

 

 

 

24

 

 

 

Total debt

 

 

 

3,253

 

 

 

3,074

 

 

 

Current maturities of long-term debt

 

 

 

(19

)

 

 

(23

)

 

 

Unamortized discount

 

 

 

(12

)

 

 

(14

)

 

 

Total long-term debt, net

 

 

 

$

3,222

 

 

 

$

3,037

 

 

 


    2013 2012
Dollars in millions Maturity Balance Rate Balance Rate
First Mortgage Bonds (secured) 2018 - 2042 $3,540
 5.60% $3,290
 5.66%
GENCO Notes (secured) 2018 - 2024 233
 5.89% 240
 5.87%
Industrial and Pollution Control Bonds (a) 2014 - 2038 158
 3.83% 161
 4.32%
Nuclear Fuel Financing 2016 100
 0.78% 
 
Other 2014 - 2027 16
 2.26% 21
 1.62%
Total debt   4,047
   3,712
  
Current maturities of long-term debt   (48)   (165)  
Unamortized premium   8
   10
  
Total long-term debt, net   $4,007
   $3,557
  
(a) Includes variable rate debt of $67.8 million at December 31, 2013 (rate of 0.11%) and 2012 (rate of 0.17%), which are hedged by fixed rate swaps of $71.4 million in 2011 and 2010.swaps.


The annual amounts of long-term debt maturities for the years 20122014 through 20162018 are summarized as follows:

Year

 

Millions of
dollars

 

2012

 

$

19

 

2013

 

164

 

2014

 

47

 

2015

 

7

 

2016

 

7

 

YearMillions of dollars
2014$48
20159
2016109
20178
2018718
In June 2013, SCE&G issued $400 million of 4.60% first mortgage bonds due June 15, 2043. Proceeds from this sale were used to pay at maturity $150 million of its 7.125% first mortgage bonds due June 15, 2013, to repay short-term debt primarily incurred as a result of SCE&G's construction program, to finance capital expenditures, and for general corporate purposes.

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

In January 2013, JEDA issued for the benefit of SCE&G $39.5 million of 4.0% tax-exempt industrial revenue bonds due February 1, 2028, and $14.7 million of 3.63% tax-exempt industrial revenue bonds due February 1, 2033. Proceeds from these sales were loaned by JEDA to SCE&G and, together with other available funds, were used to redeem prior to maturity $56.9 million of 5.2% industrial revenue bonds due November 1, 2027. The borrowings refinanced by these 2013 issuances are classified within Long-term Debt, Net in the consolidated balance sheet.

In July 2012, SCE&G issued $250$250 million of 4.35% first mortgage bonds due February 1, 2042.2042, which constituted a reopening of the prior offering of $250 million of 4.35% first mortgage bonds issued in January 2012. Proceeds from the salethese sales were used to repay short-term debt primarily incurred as a result of ourSCE&G's construction program, to finance capital expenditures and for general corporate purposes.


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

 SCE&G is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its first mortgage bonds (Bonds) have been issued. Bonds may be issued under the Mortgage in compliancean aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, other than certain Bonds issued on the basis of retired Bonds, may be issued under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12

128



consecutive months out of the 18 months immediately preceding the month of issuance are at least twice (2.0) the annual interest requirements on all debt covenants.

outstanding Bonds and Bonds to be outstanding (Bond Ratio). For the year ended December 31, 2013, the Bond Ratio was 5.28.


Lines of Credit and Short-Term Borrowings

At December 31, 20112013 and 2010,2012, SCE&G (including Fuel Company) had available the following committed LOC and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:

Millions of dollars

 

2011

 

2010

 

Lines of credit:

 

 

 

 

 

Committed long-term

 

 

 

 

 

Total

 

$

1,100

 

$

1,100

 

LOC advances

 

 

 

Weighted average interest rate

 

 

 

Outstanding commercial paper (270 or fewer days)

 

$

512

 

$

381

 

Weighted average interest rate

 

.56

%

.42

%

Letters of credit supported by an LOC

 

$

.3

 

$

.3

 

Available

 

$

588

 

$

719

 

Millions of dollars 2013 2012
Lines of credit:    
Total committed long-term $1,400
 $1,400
LOC advances 
 
Weighted average interest rate 
 
Outstanding commercial paper (270 or fewer days) $251
 $449
Weighted average interest rate 0.27% 0.42%
Letters of credit supported by an LOC $0.3
 $0.3
Available $1,149
 $951

SCE&G and Fuel Company are parties to five-year credit agreements in the amount of $1.1$1.2 billion (of which $400$500 million relates to Fuel Company), which. In addition, SCE&G is party to a three-year credit agreement in the amount of $200 million. In October 2013, the term of each of these credit agreements was extended by one year, such that the five-year agreements will expire in October 23, 2015.2018, and the three-year agreement expires in October 2016. These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10%10.7% of the aggregate $1.1 billion$1,400 million credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch and UBS Loan

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Finance LLC each provide 8%,8.9% and Deutsche Bank AG New York Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%6.3%ThreeTwo other banks provide the remaining 6%. These bank credit facilities supportsupport. Consolidated SCE&G pays fees to the issuancebanks as compensation for maintaining the committed lines of commercial paper by SCE&G (including Fuel Company). When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCE&G (including Fuel Company).

credit. Such fees were not material in any period presented.

Consolidated SCE&G is obligated with respect to an aggregate $68.3of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company. These letters of credit expire, subject to renewal, in the fourth quarter of 2014.

The Company


Consolidated SCE&G pays fees to the banks as compensation for maintaining committed lines of credit.

Such fees were not material in any period presented.


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 was not significant for any period presented. At December 31, 2013 and 2012, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $27.3 million and $49.4 million, respectively, which are included within affiliated payables on the consolidated balance sheet.



129



5.INCOME TAXES

Total

Components of income tax expense attributable to income for 2013, 2012, and 2011 2010 and 2009 isare as follows:

Millions of dollars

 

2011

 

2010

 

2009

 

Current taxes:

 

 

 

 

 

 

 

Federal

 

$

52

 

$

(56

)

$

60

 

State

 

12

 

(5

)

(9

)

Total current taxes

 

64

 

(61

)

51

 

Deferred taxes, net:

 

 

 

 

��

 

 

Federal

 

98

 

207

 

75

 

State

 

6

 

15

 

6

 

Total deferred taxes

 

104

 

222

 

81

 

Investment tax credits:

 

 

 

 

 

 

 

Deferred-state

 

 

 

20

 

Amortization of amounts deferred—state

 

(25

)

(28

)

(9

)

Amortization of amounts deferred—federal

 

(3

)

(3

)

(3

)

Total investment tax credits

 

(28

)

(31

)

8

 

Total income tax expense

 

$

140

 

$

130

 

$

140

 

Millions of dollars 2013 2012 2011
Current taxes:    
  
Federal $146
 $91
 $52
State 13
 8
 12
Total current taxes 159
 99
 64
Deferred taxes, net:      
Federal 25
 62
 98
State 9
 12
 6
Total deferred taxes 34
 74
 104
Investment tax credits:      
Amortization of amounts deferred—state (1) (13) (25)
Amortization of amounts deferred—federal (3) (3) (3)
Total investment tax credits (4) (16) (28)
Total income tax expense $189
 $157
 $140
The difference between actual income tax expense and the amount calculated from the application of the statutory 35% federal income tax rate to pre-tax income is reconciled as follows:

Millions of dollars

 

2011

 

2010

 

2009

 

Net income

 

$

306

 

$

290

 

$

281

 

Income tax expense

 

140

 

130

 

140

 

Noncontrolling interest

 

10

 

14

 

7

 

Total pre-tax income

 

$

456

 

$

434

 

$

428

 

Income taxes on above at statutory federal income tax rate

 

$

159

 

$

152

 

$

150

 

Increases (decreases) attributed to:

 

 

 

 

 

 

 

Allowance for equity funds used during construction

 

(5

)

(8

)

(10

)

State income taxes (less federal income tax effect)

 

12

 

6

 

11

 

State investment tax credits (less federal income tax effect)

 

(16

)

(18

)

(6

)

Amortization of federal investment tax credits

 

(3

)

(3

)

(3

)

Domestic production activities deduction

 

(6

)

 

(4

)

Other differences, net

 

(1

)

1

 

2

 

Total income tax expense

 

$

140

 

$

130

 

$

140

 

124


Millions of dollars 2013 2012 2011
Net income $380
 $341
 $306
Income tax expense 189
 157
 140
Noncontrolling interest 11
 11
 10
Total pre-tax income $580
 $509
 $456
       
Income taxes on above at statutory federal income tax rate $203
 $178
 $159
Increases (decreases) attributed to:      
State income taxes (less federal income tax effect) 18
 17
 12
State investment tax credits (less federal income tax effect) (5) (13) (16)
Allowance for equity funds used during construction (9) (7) (5)
Amortization of federal investment tax credits (3) (3) (3)
Section 45 tax credits (5) (5) (2)
Domestic production activities deduction (11) (9) (6)
Other differences, net 1
 (1) 1
Total income tax expense $189
 $157
 $140


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Table of Contents



The tax effects of significant temporary differences comprising Consolidated SCE&G’s net deferred tax liability of $1.4 billion at December 31, 20112013 and $1.2 billion at December 31, 20102012 are as follows:

Millions of dollars

 

2011

 

2010

 

Deferred tax assets:

 

 

 

 

 

Nondeductible reserves

 

$

82

 

$

85

 

Nuclear decommissioning

 

47

 

45

 

Unamortized investment tax credits

 

29

 

40

 

Deferred compensation

 

7

 

8

 

Unbilled revenue

 

19

 

19

 

Other

 

12

 

5

 

Total deferred tax assets

 

196

 

202

 

Deferred tax liabilities:

 

 

 

 

 

Property, plant and equipment

 

1,324

 

1,205

 

Pension plan income

 

28

 

45

 

Deferred employee benefit plan costs

 

110

 

91

 

Deferred fuel costs

 

48

 

42

 

Other

 

49

 

44

 

Total deferred tax liabilities

 

1,559

 

1,427

 

Net deferred tax liability

 

$

1,363

 

$

1,225

 

Millions of dollars 2013 2012
Deferred tax assets:    
Nondeductible accruals $17
 $73
Asset retirement obligation, including nuclear decommissioning 209
 204
Unamortized investment tax credits 19
 21
Unbilled revenue 
 14
Regulatory liability, net gain on interest rate derivative contracts settlement 27
 
Other 11
 13
Total deferred tax assets 283
 325
Deferred tax liabilities:    
Property, plant and equipment $1,494
 $1,461
Regulatory asset-asset retirement obligation 114
 107
Deferred employee benefit plan costs 54
 127
Deferred fuel costs 26
 49
Regulatory asset, unrecovered plant 55
 7
Other 62
 53
Total deferred tax liabilities 1,805
 1,804
Net deferred tax liability $1,522
 $1,479
Consolidated SCE&G is included in the consolidated federal income tax return of SCANA and files various applicable state and local income tax returns. The IRS has completed examinations of SCANA’s federal returns through 2004, and SCANA’s federal returns through 2007 are closed for additional assessment. With few exceptions, Consolidated SCE&G is no longer subject to state and local income tax examinations by tax authorities for years before 2008.

In the first quarter of 2010, in connection with a fuel cost recovery settlement (see Note 2), SCE&G accelerated the recognition of certain previously deferred state income tax credits. In the second quarter of 2010, SCE&G revised (reduced) its estimate of the benefit to be realized from the domestic production activities deduction as a result of a change in method of accounting for certain repairs for tax purposes. In the third quarter of 2010, in connection with the adoption of new retail electric base rates, and pursuant to an SCPSC order, SCE&G accelerated the recognition of additional previously deferred state income tax credits (see Note 2) and also adopted the flow through method of accounting for current and future state tax credits.

2009.


Changes to Unrecognized Tax Benefits

Millions of dollars

 

2011

 

2010

 

Unrecognized tax benefits, January 1

 

$

36

 

 

Gross increases-tax positions in prior period

 

5

 

 

Gross decreases-tax positions in prior period

 

(8

)

 

Gross increases-current period tax positions

 

5

 

$

36

 

Settlements

 

 

 

Lapse of statute of limitations

 

 

 

Unrecognized tax benefits, December 31

 

$

38

 

$

36

 

Millions of dollars 2013 2012 2011
Unrecognized tax benefits, January 1 
 $38
 $36
Gross increases-uncertain tax positions in prior period 
 
 5
Gross decreases-uncertain tax positions in prior period 
 (38) (8)
Gross increases-current period uncertain tax positions $3
 
 5
Settlements 
 
 
Lapse of statute of limitations 
 
 
Unrecognized tax benefits, December 31 $3
 $
 $38
In connection with the change in method of tax accounting for certain repair costs forin prior years, the Company had previously recorded an unrecognized tax purposes referred to above,benefit. During the first quarter of 2012, the publication of new administrative guidance from the IRS allowed Consolidated SCE&G identified approximately $38 million of unrecognized taxto recognize this benefit. BecauseSince this method change iswas primarily a temporary difference, the recognition of this additional benefit if recognized, woulddid not have a significant effect on the Consolidated SCE&G's effective tax rate.

During 2013, Consolidated SCE&G 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 $3 million. If recognized, this tax benefit would affect Consolidated SCE&G’s effective tax rate. By December 31, 2012, itIt is reasonably possible that this unrecognized tax benefit couldwill increase by as much as $12an additional $5 million or decrease by as much as $38 million. The events that could cause thesewithin the next 12 months. No other material changes are direct settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities, orin the lapsestatus of an applicable statute of limitation.

the Consolidated SCE&G’s tax positions have occurred through December 31, 2013.

Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. In connection with the resolution of the uncertainty and recognition of the tax benefit in 2012, during 2012 Consolidated SCE&G has not accrued any significant amount of interest expense related to unrecognized tax benefits or tax penalties in 2010 or 2009.  Consolidated SCE&G has accruedreversed $2 million of interest expense related to unrecognizedwhich had been accrued during 2011. Consolidated SCE&G has not recorded interest expense or penalties associated with the 2013 uncertain tax benefits in 2011.

125position.


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Table of Contents

6.DERIVATIVE FINANCIAL INSTRUMENTS

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

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

Commodity Derivatives

SCE&G uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy and financial institutions.  Cash settlement of commodity derivatives are classified as an operating activity in the consolidated statements of cash flows.

SCE&G’s tariffs include a PGA that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of these hedging activities are to be included in the PGA. As such, the cost of derivatives and gains and losses on such derivatives utilized to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. These derivative financial instruments are not designated as hedges for accounting purposes.

Interest Rate Swaps

Consolidated SCE&G 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 and are classified as an operating activity for cash flow purposes.

expense.


In anticipation of the issuance of debt, Consolidated SCE&G may use treasury rate lock or forward starting swap agreements thatagreements. Pursuant to regulatory orders issued in 2013, interest rate derivatives entered into by SCE&G after October 2013 are no longer designated as cash flow hedges.  Thehedges, and fair value changes and settlement amounts are recorded as regulatory assets and liabilities. Upon settlement, losses on swaps will be amortized over the lives of related debt issuances, and gains may be applied to under-collected fuel, be amortized to interest expense or applied as otherwise directed by the SCPSC. As discussed in Note 2, in these orders, the SCPSC directed SCE&G to recognize $41.6 million and $8.5 million of realized gains (which had been deferred in regulatory liabilities) within other income, fully offsetting revenue reductions related to under-collected fuel balances and under-collected amounts arising under the eWNA program which was terminated at the end of 2013. Prior to this regulatory authorization, such interest rate derivatives were designated as cash flow hedges, and only the effective portions of changes in fair value and payments made or received upon termination of such agreements arewere recorded in regulatory assets or regulatory liabilities. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions arewere recognized in income.

Cash payments made or received upon terminationsettlement of these financial instruments are classified as an investing activity in the consolidated statements ofactivities for cash flows.

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

flow statement purposes.


Quantitative Disclosures Related to Derivatives

SCE&G was party to natural gas derivative contracts for 2,490,000 DT and 2,460,000 DT at December 31, 2011 and 2010, respectively. 

Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $471.4$36.4 million and $421.4$971.4 million at December 31, 2013 and 2012, respectively. Consolidated SCE&G was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.3 billion and $0.0 million at December 31, 20112013 and 2010,2012, respectively.

126



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Table of Contents

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

 

 

Fair Values of Derivative Instruments

 

 

 

Asset Derivatives

 

Liability Derivatives

 

Millions of dollars

 

Balance Sheet
Location(a)

 

Fair
Value

 

Balance Sheet
Location(a)

 

Fair
Value

 

As of December 31, 2011

 

 

 

 

 

 

 

 

 

Derivatives designated as hedging instruments

 

 

 

 

 

 

 

 

 

Interest rate contracts

 

Other current assets

 

$

1

 

Other current liabilities

 

$

2

 

 

 

 

 

 

 

Other deferred credits

 

75

 

Total

 

 

 

$

1

 

 

 

$

77

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2010

 

 

 

 

 

 

 

 

 

Derivatives designated as hedging instruments

 

 

 

 

 

 

 

 

 

Interest rate contracts

 

Other deferred debits

 

$

4

 

Other current liabilities

 

$

34

 

 

 

 

 

 

 

Other deferred credits

 

1

 

Total

 

 

 

$

4

 

 

 

$

35

 

 

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Prepayments and other

 

$

1

 

 

 

 

 


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

  Fair Values of Derivative Instruments
  Asset Derivatives Liability Derivatives
Millions of dollars 
Balance Sheet
Location
 
Fair
Value
 
Balance Sheet
Location
 
Fair
Value
As of December 31, 2013    
    
Derivatives designated as hedging instruments    
    
Interest rate contracts     Other current liabilities $1
Total       $1
         
Derivatives not designated as hedging instruments        
Interest rate contracts Prepayments and other $13
 Other current liabilities $1
  Other deferred debits and other assets 19
    
Total   $32
   $1
         
As of December 31, 2012    
    
Derivatives designated as hedging instruments    
    
Interest rate contracts Prepayments and other $42
 Other current liabilities $66
  Other deferred debits and other assets 31
 Other deferred credits and other liabilities 9
Total   $73
   $75

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

Derivatives in Cash Flow Hedging Relationships

 

Gain or (Loss) Deferred
in Regulatory Accounts

 

Gain or (Loss)
Reclassified from
Deferred Accounts into Income
(Effective Portion)

 

Millions of dollars

 

(Effective Portion)

 

Location

 

Amount

 

Year Ended December 31, 2011

 

 

 

 

 

 

 

Interest rate contracts

 

$

(76

)

Interest expense

 

$

(3

)

Year Ended December 31, 2010

 

 

 

 

 

 

 

Interest rate contracts

 

$

(36

)

Interest expense

 

$

(2

)

Year Ended December 31, 2009

 

 

 

 

 

 

 

Interest rate contracts

 

$

42

 

Interest expense

 

$

(3

)

Derivatives Not Designated as Hedging Instruments

 

Gain or (Loss) Recognized in Income

 

Millions of dollars

 

Location

 

Amount

 

Year Ended December 31, 2011

 

 

 

 

 

Commodity contracts

 

Gas purchased for resale

 

$

(2

)

Year Ended December 31, 2010

 

 

 

 

 

Commodity contracts

 

Gas purchased for resale

 

$

(3

)

Year Ended December 31, 2009

 

 

 

 

 

Commodity contracts

 

Gas purchased for resale

 

$

(16

)

Derivatives in Cash Flow Hedging Relationships 
Gain or (Loss) Deferred
in Regulatory Accounts
 
Loss Reclassified from
Deferred Accounts into Income
(Effective Portion)
Millions of dollars (Effective Portion) Location Amount
Year Ended December 31, 2013  
    
Interest rate contracts $106
 Interest expense $(3)
Year Ended December 31, 2012  
    
Interest rate contracts $84
 Interest expense $(3)
Year Ended December 31, 2011  
    
Interest rate contracts $(76) Interest expense $(3)
Hedge Ineffectiveness

Other gains (losses)losses recognized in income representing ineffectiveness on interest rate hedge ineffectivenesshedges designated as cash flow hedges were $(1.1)insignificant in 2013 and 2012 and were $(1.1) million, net of tax, in 2011 and were insignificant in 2010. These amounts are recorded within interest expense on the statement of income.

1272011.



Derivatives Not Designated as Hedging Instruments Loss Recognized in Income Year Ended December 31,
Millions of dollars Location 2013 2012 2011
Commodity contracts Gas purchased for resale 
 $(1) $(2)


133




The gains reclassified to other income of Contents

$50 million offset revenue reductions as previously described herein and in Note 2.


Credit Risk Considerations

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

Certain of Consolidated SCE&G’s derivative instruments contain contingent provisions that require collateralConsolidated SCE&G to be providedprovide collateral upon the occurrence of specific events, primarily credit rating downgrades.  As of December 31, 20112013 and 2010,2012, Consolidated SCE&G hashad posted $45.0$1.5 million and $0$35.2 million, respectively, of collateral related to derivatives with contingent provisions that arewere in a net liability position. Collateral related to the positions expected to close in the next 12 months are recorded in Prepayments and other on the consolidated balance sheets. Collateral related to the noncurrent positions are recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments werehad been fully triggered as of December 31, 20112013 and 2010,2012, Consolidated SCE&G would behave been required to post an additional $31.7$0.0 million and $34.9$22.7 million, respectively, of collateral to its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of December 31, 20112013 and 2010,2012, are $76.7$1.0 million and $34.9$57.9 million, respectively.


In addition, as of December 31, 2013 and December 31, 2012, Consolidated SCE&G has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments had been fully triggered as of December 31, 2013 and December 31, 2012, Consolidated SCE&G could request $31.7 million and $32.1 million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of December 31, 2013 and December 31, 2012 is $31.7 million and $32.1 million, respectively.


134



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

       Gross Amounts Not Offset in the Statement of Financial Position  
Millions of dollarsGross Amounts of Recognized Assets Gross Amounts Offset in the Statement of Financial Position Net Amounts Presented in the Statement of Financial Position Financial Instruments Cash Collateral Received Net Amount
As of December 31, 2013           
Interest rate$32
 
 $32
 $(1) 
 $31
            
Balance sheet locationPrepayments and other $13
      
 Other deferred debits and other assets 19
      
 Total   $32
      
            
As of December 31, 2012           
Interest rate$73
 
 $73
 $(17) 
 $56
            
Balance sheet locationPrepayments and other $42
      
 Other deferred debits and other assets 31
      
 Total   $73
      

 Information related to Consolidated SCE&G's offsetting derivative liabilities follows:
       Gross Amounts Not Offset in the Statement of Financial Position  
Millions of dollarsGross Amounts of Recognized Liabilities Gross Amounts Offset in the Statement of Financial Position Net Amounts Presented in the Statement of Financial Position Financial Instruments Cash Collateral Posted Net Amount
As of December 31, 2013           
Interest rate$2
 
 $2
 $(1) $1
 $
            
Balance sheet locationOther current liabilities $2
      
 Total   $2
      
            
As of December 31, 2012           
Interest rate$75
 
 $75
 $(17) $35
 $23
            
Balance sheet locationOther current liabilities $66
      
 Other deferred credits and other liabilities 9
      
 Total   $75
      
            



135



7.FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

SCE&G values commodity derivative assets and liabilities using unadjusted NYMEX prices to determine fair value, and considers such measure of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments.

Consolidated SCE&G’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value Level 2 measurements and the level within the fair value hierarchy in which the measurements fall, were as follows:

 

 

Fair Value Measurements Using

 

Millions of dollars

 

Quoted Prices in Active
Markets for Identical Assets
(Level 1)

 

Significant Other
Observable Inputs
(Level 2)

 

As of December 31, 2011

 

 

 

 

 

Assets-Interest rate contracts

 

 

$

1

 

Liabilities-Interest rate contracts

 

 

77

 

 

 

 

 

 

 

As of December 31, 2010

 

 

 

 

 

Assets-Interest rate contracts

 

 

$

4

 

Commodity contracts

 

$

1

 

 

Liabilities-Interest rate contracts

 

 

35

 

  As of December 31, 2013 As of December 31, 2012
Millions of dollars Level 2 Level 2
Assets-Interest rate contracts $32
 $73
Liabilities-Interest rate contracts 2
 75
There were no Level 1 or Level 3 fair value measurements based on significant unobservable inputs (Level 3) for either period presented. In addition,presented and there were no transfers of fair value amounts into or out of Levels 1, and 2 or 3 during any periodthe periods presented.

Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 20112013 and December 31, 20102012 were as follows:

 

 

December 31, 2011

 

December 31, 2010

 

Millions of dollars

 

Carrying
Amount

 

Estimated
Fair
Value

 

Carrying
Amount

 

Estimated
Fair
Value

 

Long-term debt

 

$

3,241.5

 

$

3,920.3

 

$

3,059.7

 

$

3,321.8

 

  As of December 31, 2013 As of December 31, 2012
Millions of dollars 
Carrying
Amount
 
Estimated
Fair Value
 
Carrying
Amount
 
Estimated
Fair Value
Long-term debt $4,054.9
 $4,433.0
 $3,722.0
 $4,543.1
Fair values of long-term debt are based on quoted market prices of the instruments or similar instruments. For debt instruments for which no quoted market prices are available, fair values are based on net present value calculations.calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. As such, the aggregate fair values presented above are considered to be Level 2. Carrying values reflect the fair values of interest rate swaps designated as fair value hedges, based on discounted cash flow models with independently sourced market data. Early settlement of long-term debt may not be possible or may not be considered prudent.

Potential taxes and other expenses that would


Carrying values of short-term borrowings approximate their fair values, which are based on quoted prices from dealers in the commercial paper market. These fair values are considered to be incurred in an actual sale or settlement have not been considered.

128Level 2.





Table of Contents

8.EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN

Pension and Other Postretirement Benefit Plans

SCE&G participates in SCANA’s noncontributory defined benefit pension plan, which covers substantially all regular, full-time employees.employees hired before January 1, 2014. In the third quarter of 2013, SCANA amended its pension plan such that benefits are no longer offered to employees hired or rehired after December 31, 2013, and pension benefits for existing participants will no longer accrue for services performed or compensation earned after December 31, 2023. SCANA’s policy has been to fund the plan to the extentas permitted by applicable federal income tax regulations, as determined by an independent actuary.

SCANA’s pension plan provides benefits under a cash balance formula for employees hired before January 1, 2000 who elected that option and for all employees hired on or afterfrom January 1, 2000.2000 through December 31, 2013. Under the cash balance formula, benefits accumulate as a result of compensation credits and interest credits.  Employees hired before January 1, 2000 who elected to remain under the final average pay formula earn benefits based on years of credited service and the employee’s average annual base earnings received during the last three years of employment.

Benefits under the cash balance formula and the final average pay formula will continue to accrue through December 31, 2023, after which date no benefits will be accrued except that participants under the cash balance formula will continue to earn interest credits.

In addition to pension benefits, SCE&G participates in SCANA’s unfunded postretirement health care and life insurance programs which provide benefits to certain active and retired employees. Retirees hired before January 1, 2011 share in a portion of their medical care cost. Employees hired after December 31, 2010 are responsible for the full costs of retiree medical benefits elected by them. SCANA provides life insurance benefits to retirees at no charge.charge, except that employees hired after December 31, 2010 are ineligible for retiree life insurance benefits. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits.



136



The same benefit formula applies to all SCANA subsidiaries participating in the parent sponsored plans and, with regard to the pension plan, there are no legally separate asset pools. The postretirement benefit plans are accounted for as multiple employer plans. The information presented below reflects Consolidated SCE&G's portion of the obligations, assets, funded status, net periodic benefit costs, and other information reported for the parent sponsored plans as a whole. The tabular data presented reflects the use of various cost assignment methodologies and participation assumptions based on Consolidated SCE&G's past and current employees and its share of plan assets.
Changes in Benefit Obligations

The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for retirementpension benefits and the accumulated benefit obligation for other postretirement benefits are presented below.

 

 

Pension Benefits

 

Other
Postretirement
Benefits

 

Millions of dollars

 

2011

 

2010

 

2011

 

2010

 

Benefit obligation, January 1

 

$

687.8

 

$

667.4

 

$

171.5

 

$

171.4

 

Service cost

 

14.7

 

14.0

 

3.4

 

3.2

 

Interest cost

 

37.0

 

41.2

 

9.6

 

9.3

 

Plan participants’ contributions

 

 

 

2.5

 

2.4

 

Actuarial (gain) loss

 

2.6

 

(0.6

)

5.6

 

(1.1

)

Benefits paid

 

(37.1

)

(34.2

)

(11.2

)

(11.4

)

Amounts funded to parent

 

 

 

(3.0

)

(2.3

)

Benefit obligation, December 31

 

$

705.0

 

$

687.8

 

$

178.4

 

$

171.5

 

  Pension Benefits Other Postretirement Benefits
Millions of dollars 2013 2012 2013 2012
Benefit obligation, January 1 $788.4
 $705.0
 $206.0
 $178.4
Service cost 17.6
 15.7
 4.6
 3.7
Interest cost 32.6
 36.4
 8.7
 9.4
Plan participants’ contributions 
 
 2.0
 2.3
Actuarial (gain) loss (70.7) 80.3
 (27.3) 26.2
Benefits paid (50.6) (49.0) (9.3) (10.8)
Curtailment (21.6) 
 
 
Amounts funded to parent 
 
 (3.0) (3.2)
Benefit obligation, December 31 $695.7
 $788.4
 $181.7
 $206.0
The accumulated benefit obligation for retirementpension benefits was $666.7$673.2 million at the end of 20112013 and $649.0$740.2 million at the end of 2010.2012. The accumulated retirementpension benefit obligation differs from the projected retirementpension benefit obligation above in that it reflects no assumptions about future compensation levels.

Significant assumptions used to determine the above benefit obligations are as follows:

 

 

Pension
Benefits

 

Other
Postretirement
Benefits

 

 

 

2011

 

2010

 

2011

 

2010

 

Annual discount rate used to determine benefit obligation

 

5.25

%

5.56

%

5.35

%

5.72

%

Assumed annual rate of future salary increases for projected benefit obligation

 

4.00

%

4.00

%

4.00

%

4.00

%

An 8.2%

  Pension Benefits Other Postretirement Benefits
  2013 2012 2013 2012
Annual discount rate used to determine benefit obligation 5.03% 4.10% 5.19% 4.19%
Assumed annual rate of future salary increases for projected benefit obligation 3.00% 3.75% 3.75% 3.75%
A 7.4% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012.2013. The rate was assumed to decrease gradually to 5.0% for 2020 and to remain at that level thereafter.

A one percent increase in the assumed health care cost trend rate would increase the postretirement benefit obligation at December 31, 20112013 by $1.4$1.0 million and at December 31, 20102012 by $1.4$1.3 million. A one percent decrease in the assumed health care cost trend rate would decrease the postretirement benefit obligation at December 31, 20112013 by $1.2$0.9 million and at December 31, 20102012 by $1.3$1.2 million.

129



Funded Status
Millions of Dollars Pension Benefits Other Postretirement Benefits
December 31, 2013 2012 2013 2012
Fair value of plan assets $792.1
 $732.0
 
 
Benefit obligation 695.7
 788.4
 $181.7
 $206.0
Funded status $96.4
 $(56.4) $(181.7) $(206.0)

Table of Contents

Funded Status

Millions of Dollars

 

Pension Benefits

 

Other
Postretirement
Benefits

 

December 31,

 

2011

 

2010

 

2011

 

2010

 

Fair value of plan assets

 

$

695.3

 

$

745.2

 

 

 

Benefit obligations

 

705.0

 

687.8

 

$

178.4

 

$

171.5

 

Funded status (liability)

 

$

(9.7

)

$

57.4

 

$

(178.4

)

$

(171.5

)

137



Amounts recognized on the consolidated balance sheets consist of:

Millions of Dollars

 

Pension Benefits

 

Other
Postretirement
Benefits

 

December 31,

 

2011

 

2010

 

2011

 

2010

 

Noncurrent asset

 

 

$

57.4

 

 

 

Current liability

 

 

 

$

(8.3

)

$

(8.9

)

Noncurrent liability

 

$

(9.7

)

 

(170.1

)

(162.6

)

Millions of Dollars Pension Benefits Other Postretirement Benefits
December 31, 2013 2012 2013 2012
Current liability 
 
 $(7.8) $(8.5)
Noncurrent asset $96.4
 
 
 
Noncurrent liability 
 $(56.4) (173.9) (197.5)
Amounts recognized in accumulated other comprehensive incomeloss (a component of common equity) as of December 31, 20112013 and 20102012 were as follows:

Millions of Dollars

 

Pension
Benefits

 

Other
Postretirement
Benefits

 

December 31,

 

2011

 

2010

 

2011

 

2010

 

Net actuarial loss

 

$

2.4

 

$

1.8

 

$

0.4

 

$

0.3

 

Prior service cost

 

0.3

 

0.4

 

0.1

 

0.1

 

Total

 

$

2.7

 

$

2.2

 

$

0.5

 

$

0.4

 

Millions of Dollars Pension Benefits Other Postretirement Benefits
December 31, 2013 2012 2013 2012
Net actuarial loss $1.8
 $2.7
 $0.6
 $1.1
Prior service cost 0.2
 0.2
 
 
Total $2.0
 $2.9
 $0.6
 $1.1

Amounts recognized in regulatory assets as of December 31, 2013 and 2012 were as follows:
Millions of Dollars Pension Benefits Other Postretirement Benefits
December 31, 2013 2012 2013 2012
Net actuarial loss $107.7
 $257.5
 $20.1
 $46.7
Prior service cost 11.1
 23.3
 0.7
 1.2
Transition obligation 
 
 
 0.1
Total $118.8
 $280.8
 $20.8
 $48.0

In connection with the joint ownership of Summer Station, as of December 31, 20112013 and 2010,2012, SCE&G recorded within deferred debits $19.7$14.1 million and $13.0$26.8 million, respectively, attributable to Santee Cooper’s portion of shared pension costs. As of December 31, 20112013 and 2010,2012, SCE&G also recorded within deferred debits $11.4$12.6 million and $10.7$14.7 million, respectively, from Santee Cooper, representing its portion of the unfunded net postretirement benefit obligation.

Changes in Fair Value of Plan Assets

 

 

Pension Benefits

 

Millions of dollars

 

2011

 

2010

 

Fair value of plan assets, January 1

 

$

745.2

 

$

660.7

 

Actual return on plan assets

 

(12.8

)

118.7

 

Benefits paid

 

(37.1

)

(34.2

)

Fair value of plan assets, December 31

 

$

695.3

 

$

745.2

 

  Pension Benefits
Millions of dollars 2013 2012
Fair value of plan assets, January 1 $732.0
 $695.3
Actual return on plan assets 110.7
 85.7
Benefits paid (50.6) (49.0)
Fair value of plan assets, December 31 $792.1
 $732.0
Investment Policies and Strategies

The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the actuarial accrued liability forobligations of the pension plan, (2) maximizing return within reasonableoverseeing the plan's investments in an asset-liability framework that considers the funding surplus (or deficit) between assets and prudent levels ofliabilities, and overall risk in orderassociated with assets as compared to minimize contributions,liabilities, and (3) maintaining sufficient liquidity to meet benefit payment obligations on a timely basis. The pension plan is closed to new entrants effective January 1, 2014, and benefit accruals will cease effective January 1, 2024. In addition, during 2013, SCANA adopted a dynamic investment strategy for the management of the pension plan assets. The strategy will lead to a reduction in equities and an increase in long duration fixed income allocations over time with the intention of reducing volatility of funded status and pension costs in connection with the amendments to the plan.

The pension plan operates with several risk and control procedures, including ongoing reviews of liabilities, investment objectives, levels of diversification, investment managers and performance expectations. The total portfolio is constructed and maintained to provide prudent diversification with regard to the concentration of holdings in individual issues, corporations, or industries.


138



Transactions involving certain types of investments are prohibited. Equity securities heldThese include, except where utilized by a hedge fund manager, any form of private equity; commodities or commodity contracts (except for unleveraged stock or bond index futures and currency futures and options); ownership of real estate in any form other than publicly traded securities; short sales, warrants or margin transactions, or any leveraged investments; and natural resource properties. Investments made for the pension plan during the periods presented did not include SCANA common stock.

130



Tablepurpose of Contents

engaging in speculative trading are also prohibited.

The pension plan asset allocation at December 31, 20112013 and 20102012 and the target allocation for 20122014 are as follows:

 

 

Percentage of Plan Assets

 

 

 

Target
Allocation

 

At
December 31,

 

Asset Category

 

2012

 

2011

 

2010

 

Equity Securities

 

65

%

65

%

68

%

Debt Securities

 

35

%

35

%

32

%

  Percentage of Plan Assets
  
Target
Allocation
 
At
December 31,
Asset Category 2014 2013 2012
Equity Securities 58% 59% 66%
Fixed Income 33% 32% 25%
Hedge Funds 9% 9% 9%
For 2012,2014, the expected long-term rate of return on assets will be 8.25%8.00%.  In developing the expected long-term rate of return assumptions, management evaluates the pension plan’s historical cumulative actual returns over several periods, considers the expected active returns across various asset classes and assumes an asset allocation of 65%58% with equity managers, and 35%33% with fixed income managers and 9% with hedge fund managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate.

Additional rebalancing may occur subject to funded status improvements as part of the dynamic investment policy adopted for 2014.

Fair Value Measurements

Assets held by the pension plan are measured at fair value as described below. Assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 20112013 and 2010,2012, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:

 

 

 

 

Fair Value Measurements at Reporting Date Using

 

Millions of dollars

 

December 31,
2011

 

Quoted Market Prices
in Active Market for
Identical
Assets/Liabilities
(Level 1)

 

Significant
Other
Observable
Inputs
(Level 2)

 

Significant
Other
Unobservable
Inputs
(Level 3)

 

December 31, 2011

 

 

 

 

 

 

 

 

 

Common stock

 

$

298

 

$

298

 

 

 

 

 

Preferred stock

 

1

 

1

 

 

 

 

 

Mutual funds

 

169

 

19

 

$

150

 

 

 

Short-term investment vehicles

 

21

 

 

 

21

 

 

 

Government agency securities

 

29

 

 

 

29

 

 

 

Corporate debt securities

 

47

 

 

 

47

 

 

 

Loans secured by mortgages

 

11

 

 

 

11

 

 

 

Municipals

 

4

 

 

 

4

 

 

 

Common collective trusts

 

34

 

 

 

34

 

 

 

Limited partnerships

 

21

 

 

 

21

 

 

 

Multi-strategy hedge funds

 

60

 

 

 

 

 

$

60

 

 

 

$

695

 

$

318

 

$

317

 

$

60

 

December 31, 2010

 

 

 

 

 

 

 

 

 

Common stock

 

$

331

 

$

331

 

 

 

 

 

Mutual funds

 

187

 

22

 

$

165

 

 

 

Short-term investment vehicles

 

17

 

 

 

17

 

 

 

Government agency securities

 

47

 

 

 

47

 

 

 

Corporate debt securities

 

46

 

 

 

46

 

 

 

Loans secured by mortgages

 

8

 

 

 

8

 

 

 

Municipals

 

3

 

 

 

3

 

 

 

Common collective trusts

 

41

 

 

 

41

 

 

 

Limited partnerships

 

24

 

1

 

23

 

 

 

Multi-strategy hedge funds

 

41

 

 

 

 

 

$

41

 

 

 

$

745

 

$

354

 

$

350

 

$

41

 

131


  Fair Value Measurements at Reporting Date Using
Millions of dollars Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3
  December 31, 2013 December 31, 2012
Common stock $302
 $302
  
  
 $292
 $292
    
Preferred stock 1
 1
  
  
 1
 1
    
Mutual funds 278
 18
 $260
  
 226
 12
 $214
  
Short-term investment vehicles 18
   18
  
 18
   18
  
US Treasury securities 30
   30
  
 38
   38
  
Corporate debt securities 48
   48
  
 52
   52
  
Loans secured by mortgages 11
   11
  
 10
   10
  
Municipals 3
   3
  
 4
   4
  
Limited partnerships 32
 1
 31
  
 27
 1
 26
  
Multi-strategy hedge funds 69
     $69
 64
     $64
  $792
 $322
 $401
 $69
 $732
 $306
 $362
 $64

TableThere were no transfers of Contents

fair value amounts into or out of Levels 1, 2 or 3 during 2013 or 2012.


The Pension Planpension plan values common stock, preferred stock and certain mutual funds, where applicable, using unadjusted quoted prices from a national stock exchange, such as NYSE and NASDAQ, where the securities are actively traded. Other mutual funds, common collective trusts and limited partnerships are valued using the observable prices of the underlying fund assets based on trade data for identical or similar securities or from a national stock exchange for similar assets or broker quotes. Short-term investment vehicles are funds that invest in short-term fixed income instruments and are valued using observable prices of the underlying fund assets based on trade data for identical or similar securities. Government agency securities are valued using quoted market prices or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Corporate debt securities and municipals are valued based on recently executed transactions, using quoted market prices, or based on models using observable inputs from market sources such as

139



external prices or spreads or benchmarked thereto. Loans secured by mortgages are valued using observable prices based on trade data for identical or comparable instruments. Hedge funds are investedrepresent investments in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges and do not trade on a daily basis. The valuationfair value of this multi-strategy hedge fund is estimated based on the net asset value of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may impact their fair value. The estimated fair value is the price at which redemptions and subscriptions occur.

 

 

Fair Value
Measurements
Using
Significant
Unobservable
Inputs
(Level 3)

 

Millions of dollars

 

2011

 

2010

 

Beginning Balance

 

$

41

 

$

12

 

Unrealized gains (losses) included in changes in net assets

 

(1

)

2

 

Purchases, issuances, and settlements

 

20

 

27

 

Transfers in or out of Level 3

 

 

 

Ending Balance

 

$

60

 

$

41

 

  
Fair Value Measurements
Level 3
Millions of dollars 2013 2012
Beginning Balance $64
 $60
Unrealized gains included in changes in net assets 5
 4
Purchases, issuances, and settlements 
 
Transfers in or out of Level 3 
 
Ending Balance $69
 $64
Expected Cash Flows

The total benefits expected to be paid from the pension plan or from SCE&G’s assets for the other postretirement benefits plan (net of participant contributions), respectively, are as follows:


Expected Benefit Payments

 

 

 

 

Other Postretirement Benefits*

 

Millions of dollars

 

Pension Benefits

 

Excluding Medicare
Subsidy

 

Including Medicare
Subsidy

 

2012

 

$

73.4

 

$

8.7

 

$

8.4

 

2013

 

66.8

 

9.2

 

9.0

 

2014

 

61.8

 

9.9

 

9.7

 

2015

 

63.3

 

10.5

 

10.2

 

2016

 

65.5

 

11.0

 

10.8

 

2017 - 2021

 

315.5

 

61.5

 

60.5

 


*Net of participant contributions

Millions of dollars Pension Benefits Other Postretirement Benefits
2014 $61.5
 $9.3
2015 61.2
 10.0
2016 63.8
 10.6
2017 65.8
 11.1
2018 66.1
 11.6
2019 - 2023 338.4
 65.1
Pension Plan Contributions

The pension trust is adequately funded under current regulations. No contributions have been required since 1997, and as a result of closing the plan to new entrants and freezing benefit accruals in the future, SCE&G does not anticipate making significant contributions to the pension plan until after 2012.

132

for the foreseeable future.



Table of Contents

Net Periodic Benefit Cost (Income)

SCE&G records net periodic benefit cost (income) utilizing beginning of the year assumptions. Disclosures required for these plans are set forth in the following tables.


140



Components of Net Periodic Benefit Cost

 

 

Pension Benefits

 

Other Postretirement
Benefits

 

Millions of dollars

 

2011

 

2010

 

2009

 

2011

 

2010

 

2009

 

Service cost

 

$

14.7

 

$

14.0

 

$

11.9

 

$

3.4

 

$

3.2

 

$

2.8

 

Interest cost

 

37.0

 

41.2

 

42.0

 

9.6

 

9.3

 

9.5

 

Expected return on assets

 

(54.2

)

(58.0

)

(48.2

)

n/a

 

n/a

 

n/a

 

Prior service cost amortization

 

6.0

 

6.6

 

6.6

 

0.8

 

0.8

 

0.8

 

Amortization of actuarial losses

 

10.4

 

15.1

 

22.3

 

0.3

 

 

 

Transition amount amortization

 

 

 

 

(0.1

)

(0.1

)

(0.1

)

Net periodic benefit cost

 

$

13.9

 

$

18.9

 

$

34.6

 

$

14.0

 

$

13.2

 

$

13.0

 

In February 2009,

  Pension Benefits Other Postretirement Benefits
Millions of dollars 2013 2012 2011 2013 2012 2011
Service cost $17.6
 $15.7
 $14.7
 $4.6
 $3.7
 $3.4
Interest cost 32.6
 36.4
 37.0
 8.7
 9.4
 9.6
Expected return on assets (51.9) (50.4) (54.2) n/a
 n/a
 n/a
Prior service cost amortization 5.0
 6.0
 6.0
 0.6
 0.7
 0.8
Amortization of actuarial losses 14.3
 15.6
 10.4
 2.6
 1.1
 0.3
Curtailment 8.4
 
 
 
 
 
Transition obligation amortization 
 
 
 
 
 (0.1)
Net periodic benefit cost $26.0
 $23.3
 $13.9
 $16.5
 $14.9
 $14.0
Prior to July 15, 2010, the SCPSC allowed SCE&G was granted accounting orders by the SCPSC which allowed it to mitigate a significant portion of increased pension cost by deferringdefer as a regulatory asset the amount of pension cost above that which wasexceeding amounts included in then current cost of service rates for its retail electric and gas distribution regulated operations. In connection with the SCPSC's July 2010 upon the new retail electric base rates becoming effective,rate order and November 2010 natural gas RSA order, SCE&G began deferring, as a regulatory asset, all pension costcosts related to its regulated retail electric and gas operations that otherwise would have been charged to expense. In November 2010, uponEffective in January 2013, in connection with the updated gas rates becoming effective under the RSA,December 2012 rate order, SCE&G began deferring, as a regulatory asset, allamortizing previously deferred pension cost related to its regulated naturalretail electric operations totaling approximately $63 million over approximately 30 years (see Note 2) and recovering current pension costs related to retail electric operations through a rate rider that may be adjusted annually. Similarly, in connection with the October 2013 RSA order, deferred pension cost related to gas operations that otherwise would have been chargedof approximately $14 million is being amortized over approximately 14 years, and effective November 2013, SCE&G is recovering current pension expense related to expense.

gas operations through cost of service rates (see Note 2).


Other changes in plan assets and benefit obligations recognized in other comprehensive income (net of tax) were as follows:

 

 

Pension Benefits

 

Other Postretirement
Benefits

 

Millions of dollars

 

2011

 

2010

 

2009

 

2011

 

2010

 

2009

 

Current year actuarial (gain)/loss

 

$

0.7

 

$

(28.9

)

$

(9.8

)

$

0.1

 

$

 

$

0.1

 

Amortization of actuarial losses

 

(0.1

)

(1.8

)

(3.6

)

 

 

 

Amortization of prior service cost

 

(0.1

)

 

 

 

 

 

Prior service cost OCI adjustment

 

 

0.4

 

 

 

 

 

Amortization of transition obligation

 

 

 

 

 

(0.1

)

 

Total recognized in other comprehensive income

 

$

0.5

 

$

(30.3

)

$

(13.4

)

$

0.1

 

$

(0.1

)

$

0.1

 

  Pension Benefits 
Other Postretirement
Benefits
Millions of dollars 2013 2012 2011 2013 2012 2011
Current year actuarial (gain) loss $(0.8) $0.4
 $0.7
 $(0.4) $0.7

$0.1
Amortization of actuarial losses (0.1) (0.1) (0.1) (0.1) 


Amortization of prior service cost 
 (0.1)
(0.1) 
 (0.1)

Prior service cost (credit) 
 
400,000

 
 


Amortization of transition obligation 
 


 
 
 
Total recognized in other comprehensive income (loss) $(0.9) $0.2
400,000
$0.5
 $(0.5) $0.6


$0.1

Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows:
  Pension Benefits 
Other Postretirement
Benefits
Millions of dollars 2013 2012 2011 2013 2012 2011
Current year actuarial (gain) loss $(137.1) $37.9
 $61.8
 $(24.4) $25.7

$5.0
Amortization of actuarial losses (12.7) (14.0) (9.3) (2.2) (1.0)
(0.2)
Amortization of prior service cost (4.5) (5.7)
(5.5) (0.5) (0.7)
(0.7)
Prior service cost (credit) (7.7) 
400,000

 
 


Amortization of transition obligation 
 


 (0.1) (0.2) (0.2)
Total recognized in regulatory assets $(162.0) $18.2


$47.0
 $(27.2) $23.8
 $3.9



141



Significant Assumptions Used in Determining Net Periodic Benefit Cost

 

 

Pension Benefits

 

Other Postretirement
Benefits

 

 

 

2011

 

2010

 

2009

 

2011

 

2010

 

2009

 

Discount rate

 

5.56

%

5.75

%

6.45

%

$

5.72

%

5.90

%

6.45

%

Expected return on plan assets

 

8.25

%

8.50

%

8.50

%

n/a

 

n/a

 

n/a

 

Rate of compensation increase

 

4.00

%

4.00

%

4.00

%

4.00

%

4.00

%

4.00

%

Health care cost trend rate

 

n/a

 

n/a

 

n/a

 

8.00

%

8.50

%

8.00

%

Ultimate health care cost trend rate

 

n/a

 

n/a

 

n/a

 

5.00

%

5.00

%

5.00

%

Year achieved

 

n/a

 

n/a

 

n/a

 

2017

 

2017

 

2015

 

  Pension Benefits 
Other Postretirement
Benefits
  2013 2012 2011 2013 2012 2011
Discount rate 4.10%/5.07%
 5.25% 5.56% 4.19% 5.35% 5.72%
Expected return on plan assets 8.00% 8.25% 8.25% n/a
 n/a
 n/a
Rate of compensation increase 3.75%/3.00%
 4.00% 4.00% 3.75% 4.00% 4.00%
Health care cost trend rate n/a
 n/a
 n/a
 7.80% 8.20% 8.00%
Ultimate health care cost trend rate n/a
 n/a
 n/a
 5.00% 5.00% 5.00%
Year achieved n/a
 n/a
 n/a
 2020
 2020
 2017
Net periodic benefit cost for the period through September 1, 2013, was determined using a 4.10% discount rate, and net periodic benefit cost after that date was determined using a 5.07% discount rate. Similarly, estimated rates of compensation increase were changed in connection with the September 1, 2013 remeasurement.

The actuarial loss and prior service cost to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2014 are insignificant. 

The estimated amounts to be amortized from accumulated other comprehensive incomeregulatory assets into net periodic benefit cost in 20122014 are as follows:

Millions of Dollars

 

Pension
Benefits

 

Other
Postretirement
Benefits

 

Actuarial loss

 

$

0.1

 

 

Prior service cost

 

0.1

 

 

Total

 

$

0.2

 

 

133


Millions of Dollars Pension Benefits Other Postretirement Benefits
Actuarial loss $3.7
 $0.3
Prior service cost 3.1
 0.3
Total $6.8
 $0.6

Table of Contents

Other postretirement benefit costs are subject to annual per capita limits pursuant to planthe plan's design. As a result, the effect of a one-percent increase or decrease in the assumed health care cost trend rate on total service and interest cost is less than $100,000.

not significant.

Stock Purchase Savings Plan

SCE&G participates in a SCANA-sponsored defined contribution plan in which eligible employees may participate. Eligible employees may defer up to 25%75% of eligible earnings subject to certain limits and may diversify their investments. Employee deferrals are fully vested and nonforfeitable at all times. SCE&G provides 100% matching contributions up to 6% of an employee’s eligible earnings. Total matching contributions made to the plan for 2013, 2012 and 2011 2010 and 2009 were $17.3 million, $16.6$18.7million, $17.7 million and $16.6$17.3 million, respectively, and were made in the form of SCANA common stock.


9.SHARE-BASED COMPENSATION

SCE&G participates in the PlanLTECP which provides for grants of nonqualified and incentive stock options, stock appreciation rights, restricted stock, performance shares, performance units and restricted stock units to certain key employees and non-employee directors. The PlanLTECP currently authorizes the issuance of up to five million shares of SCANA’s common stock, no more than one million of which may be granted in the form of restricted stock.

Compensation costs related to share-based payment transactions are required to be recognized in the financial statements. With limited exceptions, including those liability awards discussed below, compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award.

Share-based payment awards do not have non-forfeitable rights to dividends or dividend equivalents. To the extent that the awards themselves do not vest, dividends or dividend equivalents which would have been paid on those awards do not vest.


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Liability Awards

The 2009-2011, 2010-2012,2011-2013, 2012-2014, and 2011-20132013-2015 performance cycles provide for performance measurement and award determination on an annual basis, with payment of awards being deferred until after the end of the three-year performance cycle.  In each of the performance cycles, 20% of the performance award was granted in the form of restricted share units, which are liability awards payable in cash and are subject to forfeiture in the event of retirement or termination of employment prior to the end of the cycle, subject to exceptions for death, disability or change in control.  The remaining 80% of the award was madegranted in performance shares. Each performance share has a value that is equal to, and changes with, the value of a share of SCANA common stock, and dividendstock. Dividend equivalents are accrued on the performance shares. Payoutshares and the restricted share units. Payouts of performance share awards wasare determined by SCANA’s performance against pre-determined measures of TSR as compared to a peer group of utilities (weighted 50%) and growth in “GAAP-adjusted net earnings per share from operations” (weighted 50%). Payouts under the 2009-2011 performance cycle were earned for each year that performance goals were met during the three-year cycle.  Awards were designated as target shares of SCANA common stock and were paid in cash at SCANA’s discretion in February 2012.

Compensation cost of all these liability awards is recognized over their respective three-year performance periods based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Awards under the 2011-2013 performance cycle were paid in cash at SCANA’s discretion in February 2014. Cash-settled liabilities related to similar prior programsprogram cycles were paid totaling $2.5approximately $3.2 million in 2011, $2.42013, $8.7 million in 20102012 and $1.7$2.5 million in 2009.

2011.

Fair value adjustments for performance awards resulted in compensation expense recognized in the statements of income totaling $4.0$5.5 million in 2011, $9.02013, $9.5 million in 20102012 and $4.5$4.0 million in 2009.2011. Fair value adjustments resulted in capitalized compensation costs of $0.2$0.5 million in 2011, $2.22013, $2.1 million in 20102012 and $0.9$0.2 million in 2009.

2011.


Equity AwardsAward

Ins

No equity awards were made during any period presented, and the 2008-2010 performance cycle, 20%effects of the performance award was granted in the formprevious such awards on Consolidated SCE&G's results of restricted (nonvested) shares rather than restricted share units.  A summary of activity related to these nonvested shares follows:

Nonvested Shares

 

Shares

 

Weighted Average
Grant-Date
Fair Value

 

Nonvested at January 1, 2009

 

74,588

 

$

37.33

 

Forfeited

 

(2,399

)

37.33

 

Nonvested at December 31, 2009

 

72,189

 

37.33

 

Vested

 

(72,189

 

37.33

 

Nonvested at December 31, 2010

 

 

 

 

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Nonvested shares were granted at a price corresponding to the opening price of SCANA common stock on the date of the grant. As of December 31, 2010 all compensation cost related to nonvested share-based compensation arrangements under the Plan had been recognized.  SCE&G expensed compensation costs for nonvested shares of $0.1 million in each of 2010operations, cash flows and 2009.  Tax benefits and capitalized compensation costs in 2010 and 2009financial position were not significant.

A summary of activity related to nonqualified stock options follows:

Stock Options

 

Number of
Options

 

Weighted Average
Exercise Price

 

Outstanding-January 1, 2009

 

106,464

 

$

27.44

 

Exercised

 

(2,875

)

27.50

 

Outstanding-December 31, 2009

 

103,589

 

27.44

 

Exercised

 

(53,246

)

27.40

 

Outstanding-December 31, 2010

 

50,343

 

27.49

 

Exercised

 

(40,267

)

27.48

 

Outstanding-December 31, 2011

 

10,076

 

27.52

 

No stock options were granted or forfeited and all options were fully vested during the periods presented.  The options expire ten years after their respective grant dates and all options currently outstanding will expire in 2012.  At December 31, 2011, all outstanding options were currently exercisable at a price of $27.52, and had a weighted-average remaining contractual life of less than one year.

The exercise of stock options during the periods presented were satisfied using original issue shares.  For the years ended December 31, 2011, 2010 and 2009, cash realized upon the exercise of options and related tax benefits were not significant.


10.COMMITMENTS AND CONTINGENCIES

Nuclear Insurance

Under Price-Anderson, SCE&G (for itself and on behalf of Santee-Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the company’s nuclear power plant.  Price-Anderson provides funds up to $12.6$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$375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors.  Each reactor licensee is currently liable for up to $117.5$127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5$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 $78.3$84.8 million per incident, but not more than $11.7$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 the nuclear facilitySummer Station Unit 1 for property damage and outage costs up to $2.75 billion.$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 Ownersowners of the New Units up to $500$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 premiums, SCE&G’s portion of the prospectiveretrospective premium assessment would not exceed $37.3 million.

$41.6 million


To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G 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 Consolidated SCE&G’s results of operations, cash flows and financial position.

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SCE&G, on behalf of Contents

Environmental

itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $5.4 billion for plant and related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC.


SCE&G's current ownership share in the New Units is 55%. Under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units. Under the terms of this agreement SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, will acquire an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and will acquire the final 2% no later than the second anniversary of such commercial operation date. Under the terms of the agreement SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost of the percentage conveyed as of the date of conveyance, which SCE&G estimates will be approximately $500 million for the entire 5% interest. In December 2009,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 would be reflected in a revised rates filing under the BLRA.

The Consortium has experienced delays in the schedule for fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules are a focus area of the Consortium, including sub-modules for module CA20, which is part of the auxiliary building, and CA01, which houses components inside the containment vessel. Modules CA20 and CA01 are considered critical path items for both New Units. All sub-modules for CA20 have been received on site and its fabrication is underway. CA20 is expected to be ready for placement on the nuclear island of the first New Unit in the first quarter of 2014. In addition, the delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow it to be ready for placement on the nuclear island of the first New Unit during the third quarter of 2014. With this schedule, the Consortium continues to indicate that the substantial completion of the first New Unit is expected to be late 2017 or the first quarter of 2018 and that the substantial completion of the second New Unit is expected to be approximately twelve months after that of the first New Unit. The substantial completion dates currently approved by the SCPSC for the first and second New Units are March 15, 2017 and May 15, 2018, respectively. The SCPSC has also approved an 18-month contingency period beyond each of these dates. The preliminary expected new substantial completion dates are within the contingency periods. SCE&G cannot predict with certainty the extent to which the issue with the sub-modules or the delays in the substantial completion of the New Units will result in increased project costs. However, the preliminary estimate of the delay-related costs associated with SCE&G's 55% share of the New Units is approximately $200 million. SCE&G has not accepted responsibility for any of these delay-related costs and expects to have further discussions with the Consortium regarding such responsibility. Additionally, the EPC Contract provides for liquidated damages in the event of a delay in the completion of the New Units, which will also be included in discussions with the Consortium. SCE&G believes its responsibility for any portion of the $200 million estimate should ultimately be substantially less, once all of the relevant factors are considered.

In addition to the above-described project delays, SCE&G is also aware of financial difficulties at a supplier responsible for certain significant components of the project.  The Consortium is monitoring the potential for disruptions in such equipment fabrication and possible responses.   Any disruptions could impact the project's schedule or costs, and such impacts could be material.

The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude.  During the course of activities under the EPC Contract, issues have materialized that impact project budget and schedule. Claims specifically relating to COL delays,
design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock
conditions at the site resulted in assertions of contractual entitlement to recover additional costs to be incurred. The resolution
of these specific claims is discussed in Note 2. SCE&G expects to resolve any disputes that arise in the future, including any which may arise with respect to the delay-related costs discussed above, through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time, will be recoverable through rates.

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 schedule and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and

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design resource allocations, procurement schedules, construction work crew assignments, and other items. The result will be a revised fully integrated construction schedule that will provide detailed and itemized information on individual budget and cost categories, cost estimates at completion for all non-firm and fixed scopes of work, and the timing of specific construction activities and cash flow requirements. SCE&G anticipates that the revised schedule and the cost estimate at completion for all non-firm and fixed scopes of work will be finalized in the third quarter of 2014. SCE&G plans to reevaluate and reschedule its owners cost estimates and cash flow requirements in light of the new schedule.

When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units.  In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation, as well as a request for information related to emergency plant staffing.  These conditions and requirements are responsive to the NRC's Near-Term Task Force report titled “Recommendations for Enhancing Reactor Safety in the 21st Century.”  This report was prepared in the wake of the March 2011 earthquake-generated tsunami, which severely damaged several nuclear generating units and their back-up cooling systems in Japan.  SCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the construction and operation of the New Units, and SCE&G, pursuant to the license condition, prepared and submitted an integrated response plan for the New Units to the NRC in August 2013.  SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New Units.

Subject to a national megawatt capacity limitation, the electricity to be produced by the New Units (advanced nuclear units, as defined) is expected to qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code. Following the pouring of safety-related concrete for each of the New Units’ reactor buildings (March 2013 for the first New Unit and November 2013 for the second New Unit), SCE&G has applied to the IRS for its allocations of such national megawatt capacity limitation. The IRS will forward the applications to the DOE for appropriate certification.

Environmental
As part of the President's Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA issuedwas directed to issue a final finding that atmospheric concentrationsrevised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of GHG endanger public health and welfare within the meaning of Section 202(a) of the CAA.carbon dioxide from newly constructed fossil fuel-fired units. The rule which became effectivefinal 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 final rule, but does not plan to construct new coal-fired units in January 2010, enablesthe near future. The Memorandum also directed the EPA to regulate GHG emissions under the CAA. The EPA has committedissue standards, regulations, or guidelines for existing units by June 1, 2014, to issue newbe made final no later than June 1, 2015. Consolidated SCE&G also cannot predict when rules regulating such emissions in 2012.will become final for existing units, if at all, or what conditions they may impose on Consolidated SCE&G, if any. Consolidated SCE&G expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.


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 below.

In 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels.  CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide.  SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements.  On July 6, 2011 the EPA issued the Cross-State Air Pollution Rule (CSAPR).CSAPR.  This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. On August 21, 2012, the Court of Appeals vacated CSAPR and left CAIR in place. The EPA's petition for rehearing of the Court of Appeals' order was denied. In June 2013 the U.S. Supreme Court agreed to review the Court of Appeals' decision and oral arguments were held on December 10, 2013. A decision is still pending. Air quality

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control installations that SCE&G and GENCO have already completed should assist the Company in complyinghave allowed Consolidated SCE&G to comply with the Cross-State Air Pollution Rulereinstated CAIR and the reinstated CAIR.  The Companywill also allow it to comply with CSAPR, if reinstated. Consolidated SCE&G will continue to pursue strategies to comply with all applicable environmental regulations.  Any costs incurred to comply with such regulations are expected to be recoverable through rates.

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

In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court


The CWA provides for the Districtimposition of Columbia vacatedeffluent limitations that require treatment for wastewater discharges. Under the rule for electric utility steam generating units.  In March 2011, the EPA proposedCWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new standards for mercury and other specified air pollutants.effluent limitations would be incorporated. The rule, which becomes effective on April 16, 2012, provides up to four years for facilities to meet the standards.  The rule is currently being evaluated by the Company. Any costs incurred to comply with this rule or other rules issued by the EPAELG Rule was published in the future areFederal Register on June 7, 2013, and is expected to be recoverable through rates.

SCE&G has been named, along with 53 others, byfinalized May 22, 2014. The EPA expects compliance as soon as possible after July 2017 but no later than July 2020.


Additionally, the EPA asis expected to issue a PRP at the AER Superfund site locatedrule that modifies requirements for existing cooling water intake structures in Augusta, Georgia. The PRPs funded a Remedial Investigationearly 2014. Consolidated SCE&G is conducting studies and Risk Assessment which was completed and approved by the EPA and funded a Feasibility Study that was completed in 2010. A clean-up cost has been estimated and the PRPs have agreedis developing or implementing compliance plans for these initiatives. Congress is expected to an allocation of those costs based primarily on volume and type of material each PRP sentconsider further amendments to the site. SCE&G’s allocation did notCWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones. These provisions, if passed, could have a material impact on itsthe financial condition, results of operations and cash flows of SCE&G and GENCO. Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates.
In response to a federal court order to establish a definite timeline for a CCR rule, the EPA has said it will issue new federal regulations affecting the management and disposal of CCRs, such as ash, by December 2014. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO. While Consolidated SCE&G cannot predict how extensive the regulations will be, Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates.
The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998. The Nuclear Waste Act also imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or financial condition.

High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2013, 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 has commenced construction of 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. In addition, the state of South Carolina has similar laws. SCE&G maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify 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 couldmay differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. SCE&G defers site assessmentSuch amounts are recorded in regulatory assets and cleanup costs and expects to recover themamortized, 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.DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue until 20142017 and will cost an additional $8.3 million.$20.2 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates and insurance settlements.rates.  At December 31, 2011,2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.9$36.7 million and are included in regulatory assets.

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Claims and Litigation

In May 2004, a purported class action lawsuit currently styled as Douglas E. Gressette and Mark Rudd, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Communications, Inc. was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiffs alleged that SCE&G made improper use of certain electric transmission easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCE&G’s electricity-related internal communications and asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment.  While SCE&G and SCI believe their actions were consistent with governing law and the applicable documents granting easements and rights-of-way, this case, with Circuit Court approval in August 2010, has been settled as to all easements and rights of ways currently containing fiber optic communications lines in South Carolina.  This settlement did not have a material impact on Consolidated SCE&G’s results of operations, cash flows or financial condition.

Consolidated SCE&G is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without a material impact on Consolidated SCE&G’s results of operations, cash flows or financial condition.


Operating Lease Commitments

Consolidated SCE&G is obligated under various operating leases with respect tofor vehicles, office space, furniture and equipment. Leases expire at various dates through 2057. Rent expense totaled approximately $10.8$13.6 million in 2011, $9.32013, $9.6 million in 20102012 and $16.5$10.8 million in 2009.2011. Future minimum rental payments under such leases are as follows:

 

 

Millions of dollars

 

2012

 

$

7

 

2013

 

6

 

2014

 

2

 

2015

 

1

 

2016

 

 

Thereafter

 

21

 

Total

 

$

37

 

Purchase Commitments

Consolidated SCE&G is obligated for purchase commitments that expire at various dates through 2034. Amounts expended for coal supply, nuclear fuel contracts, construction projects and other commitments totaled $717.8 million in 2011, $859.7 million in 2010 and $756.9 million in 2009. Future payments under such purchase commitments are as follows:

 

 

Millions of dollars

 

2012

 

$

1,459

 

2013

 

965

 

2014

 

836

 

2015

 

767

 

2016

 

773

 

Thereafter

 

1,038

 

Total

 

$

5,838

 

 Millions of dollars
2014$4
20153
20162
20171
20181
Thereafter19
Total$30

Asset Retirement Obligations

Consolidated SCE&G recognizes a liability for the fairpresent value of an ARO when incurred if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.

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The legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation relate primarily to Consolidated SCE&G’s regulated utility operations. As of December 31, 2011,2013, Consolidated SCE&G has recorded an AROAROs of approximately $124$191 million for nuclear plant decommissioning (see Note 1) and an AROAROs of approximately $326$356 million for other conditional obligations primarily related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future.


A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations is as follows:

Millions of dollars

 

2011

 

2010

 

Beginning balance

 

$

478

 

$

458

 

Liabilities incurred

 

 

1

 

Liabilities settled

 

(4

)

(1

)

Accretion expense

 

23

 

24

 

Revisions in estimated cash flows

 

(47

)

(4

)

Ending Balance

 

$

450

 

$

478

 

Millions of dollars 2013 2012
Beginning balance $535
 $450
Liabilities incurred 5
 
Liabilities settled (4) (5)
Accretion expense 24
 23
Revisions in estimated cash flows (13) 67
Ending Balance $547
 $535

11.AFFILIATED TRANSACTIONS

CGT transports natural gas to SCE&G to serve retail gas customers and certain electric generation requirements.  Such purchases totaled approximately $30.8$33.3 million in 2011, $32.02013, $35.9 million in 20102012 and $30.4$30.8 million in 2009.2011.  SCE&G had approximately $2.5$3.3 million and $2.1$3.4 million payable to CGT for transportation services at December 31, 20112013 and December 31, 2010,2012, respectively.

SCE&G had approximately $1.3 million receivable from CGT for transportation services at December 31, 2013 and an insignificant receivable amount at December 31, 2012.


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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 $187.4$166.9 million in 2011, $182.52013, $125.5 million in 20102012 and $160.8$187.4 million in 2009.2011. SCE&G’s payables to SEMI for such purposes were $13.2$12.5 million and $16.1$13.1 million as of December 31, 20112013 and 2010,2012, respectively.

SCE&G owns 40% of Canadys Refined Coal, LLC and 10% of Cope Refined Coal, LLC, bothwhich is involved in the manufacturing and selling of refined coal to reduce emissions. SCE&G accounts for these investmentsthis investment using the equity method. SCE&G’s receivablesreceivable from these affiliates were $8.5this affiliate was $18.0 million at December 31, 20112013 and insignificant$1.8 million at December 31, 2010.2012.  SCE&G’s payablespayable to these affiliates were $8.6this affiliate was $18.0 million at December 31, 20112013 and insignificant$1.8 million at December 31, 2010.2012.  SCE&G’s total purchases to this affiliate were $123.8$134.2 million in 20112013 and $97.3$111.6 million in 2010.2012. SCE&G’s total sales to this affiliate were $123.3$133.6 million in 20112013 and $96.9$111.1 million in 2010.

Consolidated SCE&G participates in a utility money pool. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions was not significant for any period presented. At December 31, 2011 and 2010, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $58.5 million and $71.0 million, respectively.

2012.


An affiliate processes and pays invoices for Consolidated SCE&G and is reimbursed by them.reimbursed. Consolidated SCE&G owed $43.0$49.1 million and $39.8$39.4 million to the affiliate at December 31, 20112013 and 2010,2012, respectively, for invoices paid by the affiliate on behalf ofits behalf.

SCANA Services provides the following services to Consolidated SCE&G.

&G, which are rendered at direct or allocated cost: information systems services, customer services, marketing and sales, human resources, corporate compliance, purchasing, financial services, risk management, public affairs, legal services, investor relations, gas supply and capacity management, strategic planning, and general administrative services. Costs for these services totaled $285.6 million in 2013, $305.6 million in 2012 and $302.6 million in 2011.


12.SEGMENT OF BUSINESS INFORMATION

Consolidated SCE&G’s reportable segments are listedfollow the same accounting policies as those described in the following table. Consolidated SCE&G uses operating income to measure profitability for its regulated operations. Therefore, earnings available to common shareholders are not allocated to the Electric Operations and gas segments. Intersegment revenues were not significant.

Note 1.

Electric Operations is primarily engaged in the generation, transmission, and distribution of electricity, and is regulated by the SCPSC and FERC. Gas Distribution is engaged in the purchase and sale, primarily at retail, of natural gas, and is regulated by the SCPSC.

138



148



Table of Contents

Disclosure of Reportable Segments (Millions of dollars)

 

 

Electric
Operations

 

Gas
Distribution

 

Adjustments/
Eliminations

 

Consolidated
Total

 

2011

 

 

 

 

 

 

 

 

 

External Revenue

 

2,432

 

387

 

 

2,819

 

Operating Income

 

616

 

40

 

(2

)

654

 

Interest Expense

 

23

 

 

181

 

204

 

Depreciation and Amortization

 

271

 

25

 

(10

)

286

 

Segment Assets

 

8,222

 

622

 

2,193

 

11,037

 

Expenditures for Assets

 

806

 

60

 

(18

)

848

 

Deferred Tax Assets

 

9

 

n/a

 

(1

)

8

 

 

 

 

 

 

 

 

 

 

 

2010

 

 

 

 

 

 

 

 

 

External Revenue

 

$

2,374

 

$

441

 

$

 

$

2,815

 

Intersegment Revenue

 

554

 

52

 

(2

)

604

 

Operating Income

 

22

 

 

164

 

186

 

Interest Expense

 

263

 

22

 

(14

)

271

 

Depreciation and Amortization

 

7,882

 

590

 

2,102

 

10,574

 

Segment Assets

 

752

 

39

 

(20

)

771

 

Expenditures for Assets

 

5

 

n/a

 

10

 

15

 

Deferred Tax Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2009

 

 

 

 

 

 

 

 

 

External Revenue

 

$

2,149

 

$

420

 

 

$

2,569

 

Intersegment Revenue

 

 

2

 

$

(2

)

 

Operating Income

 

505

 

43

 

(1

)

547

 

Interest Expense

 

15

 

 

149

 

164

 

Depreciation and Amortization

 

244

 

21

 

(10

)

255

 

Segment Assets

 

7,312

 

558

 

1,943

 

9,813

 

Expenditures for Assets

 

817

 

39

 

(105

)

751

 

Deferred Tax Assets

 

n/a

 

n/a

 

n/a

 

n/a

 

  
Electric
Operations
 
Gas
Distribution
 
Adjustments/
Eliminations
 
Consolidated
Total
2013        
External Revenue $2,431
 $414
 
 $2,845
Operating Income 679
 58
 
 737
Interest Expense 19
 
 $198
 217
Depreciation and Amortization 294
 26
 (7) 313
Segment Assets 9,488
 686
 2,526
 12,700
Expenditures for Assets 907
 45
 51
 1,003
Deferred Tax Assets 10
 n/a
 (10) 
         
2012  
  
  
  
External Revenue $2,453
 $356
 
 $2,809
Operating Income 668
 49
 
 717
Interest Expense 21
 
 $190
 211
Depreciation and Amortization 278
 25
 (10) 293
Segment Assets 8,989
 659
 2,456
 12,104
Expenditures for Assets 999
 56
 (77) 978
Deferred Tax Assets 9
 n/a
 (9) 
         
2011  
  
  
  
External Revenue $2,432
 $387
 
 $2,819
Operating Income 616
 40
 $(2) 654
Interest Expense 23
 
 181
 204
Depreciation and Amortization 271
 25
 (10) 286
Segment Assets 8,222
 622
 2,193
 11,037
Expenditures for Assets 806
 60
 (18) 848
Deferred Tax Assets 9
 n/a
 (1) 8
Management uses operating income to measure segment profitability for regulated operations and evaluates utility plant, net, for its segments. As a result, Consolidated SCE&G does not allocate interest charges, income tax expense, earnings available to common shareholder or assets other than utility plant to its segments. InterestIntersegment revenue and interest income iswere not reported by segment and is not material.significant. Consolidated SCE&G’s deferred tax assets are netted with deferred tax liabilities for reporting purposes.

The consolidated financial statements report operating revenues which are comprised of the reportable segments. Revenues from non-reportable segments are included in Other Income. Therefore, the adjustments to total operating revenues remove revenues from non-reportable segments. Segment Assets include utility plant, net for all reportable segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for the segments. Adjustments to Interest Expense and Deferred Tax Assets include amounts that are not allocated to the segments. Expenditures for Assets are adjusted for revisions to estimated cash flows related to asset retirement obligations, and totals not allocated to other segments.



149



13.QUARTERLY FINANCIAL DATA (UNAUDITED)

 

 

First
Quarter

 

Second
Quarter

 

Third
Quarter

 

Fourth
Quarter

 

Annual

 

2011 Millions of dollars

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

 

$

704

 

$

691

 

$

797

 

$

627

 

$

2,819

 

Operating income

 

151

 

137

 

220

 

146

 

654

 

Net income attributable to SCE&G

 

68

 

59

 

117

 

62

 

306

 

2010 Millions of dollars

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

 

$

722

 

$

652

 

$

777

 

$

664

 

$

2,815

 

Operating income

 

123

 

138

 

198

 

145

 

604

 

Net income attributable to SCE&G

 

62

 

60

 

106

 

62

 

290

 

139

 Millions of dollars 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 Annual
2013  
  
  
  
  
Total operating revenues $728
 $696
 $776
 $645
 $2,845
Operating income 191
 180
 255
 111
 737
Net Income 92
 88
 139
 72
 391
Earnings Available to Common Shareholder 89
 85
 136
 70
 380
           
2012  
  
  
  
  
Total operating revenues $663
 $661
 $777
 $708
 $2,809
Operating income 156
 165
 241
 155
 717
Net Income 72
 78
 132
 70
 352
Earnings Available to Common Shareholder 69
 76
 129
 67
 341


150




Table of Contents

PART II,

ITEMS 9, 9A AND 9B

PART III

AND

PART IV

140



Table of Contents

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not Applicable.

ITEM 9A.  CONTROLS AND PROCEDURES

SCANA:

Evaluation of Disclosure Controls and Procedures:

As of December 31, 2011,2013, an evaluation was performed under the supervision and with the participation of SCANA’s management, including the CEO and CFO, of the effectiveness of the design and operation of SCANA’s disclosure controls and procedures. For purposes of this evaluation, disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by SCANA in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to SCANA’s management, including the CEO and CFO, as appropriate to allow timely discussionsdecisions regarding required disclosure. Based on that evaluation, SCANA’s management, including the CEO and CFO, concluded that SCANA’s disclosure controls and procedures were effective as of December 31, 2011.2013.

Management’s Evaluation of Internal Control Over Financial Reporting:

As of December 31, 2013, an evaluation was performed under the supervision and with the participation of SCANA’s management, including the CEO and CFO, of any change in SCANA's internal controls over financial reporting during the quarter ended December 31, 2013. There has been no change in SCANA’s internal controls over financial reporting during the quarter ended December 31, 20112013 that has materially affected or is reasonably likely to materially affect SCANA’s internal control over financial reporting.

Management’s Evaluation of Internal Control Over Financial Reporting:


Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, management is required to include in this Form 10-K an internal control report wherein management states its responsibility for establishing and maintaining adequate internal control structure and procedures for financial reporting and that it has assessed, as of December 31, 2011,2013, the effectiveness of such structure and procedures. This management report follows.

MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of SCANA is responsible for establishing and maintaining adequate internal control over financial reporting. SCANA’s internal control system was designed by or under the supervision of SCANA’s management, including the CEO and CFO, to provide reasonable assurance to SCANA’s management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of the internal control over financial reporting may deteriorate in future periods due to either changes in conditions or declining levels of compliance with policies or procedures.

SCANA’s management assessed the effectiveness of SCANA’s internal control over financial reporting as of December 31, 2011.2013.  In making this assessment, SCANA used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework (1992). Based on this assessment, SCANA’s management believes that, as of December 31, 2011,2013, internal control over financial reporting is effective based on those criteria.

SCANA’s independent registered public accounting firm has issued an attestation report on SCANA’s internal control over financial reporting. This report follows.

141



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Table of Contents

ATTESTATION REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

SCANA Corporation

Cayce, South Carolina


We have audited the internal control over financial reporting of SCANA Corporation and subsidiaries (the “Company”"Company") as of December 31, 2011,2013, based on criteria established in Internal Control—Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’sCompany's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’sCompany's internal control over financial reporting based on our audit.


We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.


A company’scompany's internal control over financial reporting is a process designed by, or under the supervision of, the company’scompany's principal executive and principal financial officers, or persons performing similar functions, and effected by the company’scompany's board of directors, management, and other personnel 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. A company’scompany's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’scompany's assets that could have a material effect on the financial statements.


Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011,2013, based on the criteria established in Internal Control-IntegratedControl - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.


We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 20112013, of the Company and our report dated February 29, 2012,28, 2014, expressed an unqualified opinion on those financial statements and financial statement schedule.


/s/DELOITTE & TOUCHE LLP

Charlotte, North Carolina

February 29, 2012

28, 2014

142



152



Evaluation of Disclosure Controls and Procedures:

As of December 31, 2011,2013, an evaluation was performed under the supervision and with the participation of SCE&G’s management, including the CEO and CFO, of the effectiveness of the design and operation of SCE&G’s disclosure controls and procedures. For purposes of this evaluation, disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by SCE&G in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to SCE&G’s management, including the CEO and CFO, as appropriate to allow timely discussionsdecisions regarding required disclosure. Based on that evaluation, SCE&G’s management, including the CEO and CFO, concluded that SCE&G’s disclosure controls and procedures were effective as of December 31, 2011.2013.

Management’s Evaluation of Internal Control Over Financial Reporting:
As of December 31, 2013, an evaluation was performed under the supervision and with the participation of SCE&G’s management, including the CEO and CFO, of any change in SCE&G's internal controls over financial reporting during the quarter ended December 31, 2013. There has been no change in SCE&G’s internal controls over financial reporting during the quarter ended December 31, 20112013 that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.

Management’s Evaluation of Internal Control Over Financial Reporting:


Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, management is required to include in this Form 10-K an internal control report wherein management states its responsibility for establishing and maintaining adequate internal control structure and procedures for financial reporting and that it has assessed, as of December 31, 2011,2013, the effectiveness of such structure and procedures. This management report follows.

MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of SCE&G is responsible for establishing and maintaining adequate internal control over financial reporting. SCE&G’s internal control system was designed by or under the supervision of SCE&G’s management, including the CEO and CFO, to provide reasonable assurance to SCE&G’s management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of the internal control over financial reporting may deteriorate in future periods due to either changes in conditions or declining levels of compliance with policies or procedures.

SCE&G’s management assessed the effectiveness of SCE&G’s internal control over financial reporting as of December 31, 2011.2013. In making this assessment, SCE&G used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (1992). Based on this assessment, SCE&G’s management believes that, as of December 31, 2011,2013, internal control over financial reporting is effective based on those criteria.

ITEM 9B.  OTHER INFORMATION


153

Not applicable.

143




ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

SCANA: A list of SCANA’s executive officers is in Part I of this annual report at page 26.25. The other information required by Item 10 is incorporated herein by reference to the captions “NOMINEES FOR DIRECTORS,” “CONTINUING DIRECTORS,” “BOARD MEETINGS-COMMITTEES OF THE BOARD”, “GOVERNANCE INFORMATION-SCANA’s Code of Conduct & Ethics” and “OTHER INFORMATION-Section 16(a) Beneficial Ownership Reporting Compliance” in SCANA’s definitive proxy statement for the 20122014 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA’s fiscal year.


SCE&G: Not applicable. 


ITEM 11.  EXECUTIVE COMPENSATION

SCANA: The information required by Item 11 is incorporated herein by reference to the captions “COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION,“Compensation Committee Interlocks and Insider Participation,“COMPENSATION DISCUSSION AND ANALYSIS,“Compensation Discussion and Analysis,COMPENSATION COMMITTEE REPORT,Compensation Committee Report,“SUMMARY COMPENSATION TABLE,“Summary Compensation Table,“2011 GRANTS OF PLAN-BASED AWARDS,“2013 Grants of Plan-Based Awards,“OUTSTANDING EQUITY AWARDS AT 2011 FISCAL YEAR-END,“Outstanding Equity Awards at 2013 Fiscal Year-End,“2011 OPTION EXERCISES AND STOCK VESTED,“2013 Option Exercises and Stock Vested,“PENSION BENEFITS,“Pension Benefits,“2011 NONQUALIFIED DEFERRED COMPENSATION,“2013 Nonqualified Deferred Compensation,” and “POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL,“Potential Payments Upon Termination or Change in Control,” under the heading “EXECUTIVE COMPENSATION” and the heading “2011 DIRECTOR“DIRECTOR COMPENSATION” in SCANA’s definitive proxy statement for the 20122014 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA’s fiscal year.


SCE&G: Not applicable.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

SCANA: Information required by Item 12 is incorporated herein by reference to the caption “SHARE OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT” in SCANA’s definitive proxy statement for the 20122014 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA’s fiscal year.

Equity securities issuable under SCANA’s compensation plans at December 31, 20112013 are summarized as follows:

Plan Category

 

Number of
securities
to be issued
upon exercise
of outstanding
options, warrants
and rights

 

Weighted-average
exercise price
of outstanding options,
warrants
and rights

 

Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column (a))

 

 

 

(a)

 

(b)

 

(c)

 

Equity compensation plans approved by security holders:

 

 

 

 

 

 

 

Long-Term Equity Compensation Plan

 

10,076

 

27.52

 

3,138,638

 

Non-Employee Director Compensation Plan

 

n/a

 

n/a

 

153,509

 

Equity compensation plans not approved by security holders

 

n/a

 

n/a

 

n/a

 

Total

 

10,076

 

27.52

 

3,292,147

 

Plan Category
Number of
securities
to be issued
upon exercise
of outstanding
options, warrants
and rights
Weighted-average
exercise price
of outstanding options,
warrants
and rights
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column (a))
(a)(b)(c)
Equity compensation plans approved by security holders:-
Long-Term Equity Compensation Plann/an/a3,138,638
Non-Employee Director Compensation Plann/an/a100,886
Equity compensation plans not approved by security holdersn/an/an/a
Totaln/an/a3,239,524
SCE&G: Not applicable.



154



ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

SCANA: The information required by Item 13 is incorporated herein by reference to the caption “RELATED PARTY TRANSACTIONS” in SCANA’s definitive proxy statement for the 20122014 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA’s fiscal year.

144


SCE&G: Not applicable.




Table of Contents

ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES

SCANA: The information required by Item 14 is incorporated herein by reference to “PROPOSAL 4-APPROVAL2-APPROVAL OF THE APPOINTMENT OF THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM” in SCANA’s definitive proxy statement for the 20122014 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities and Exchange Act of 1934 within 120 days after the end of SCANA’s fiscal year.

SCE&G: The Audit Committee Charter requires the Audit Committee to pre-approve all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed by the independent registered accounting firm. Pursuant to a policy adopted by the Audit Committee, its Chairman may pre-approve the rendering of services on behalf of the Audit Committee. Decisions by the Chairman to pre-approve the rendering of services are presented to the Audit Committee at its next scheduled meeting.

Independent Registered Public Accounting Firm’s Fees

The following table sets forth the aggregate fees, all of which were approved by the Audit Committee, charged to SCE&G and its consolidated affiliates for the fiscal years ended December 31, 20112013 and 20102012 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates.

 

 

2011

 

2010

 

Audit Fees(1)

 

$

1,754,899

 

$

1,594,800

 

Audit-Related Fees(2)

 

66,957

 

66,713

 

Total Fees

 

$

1,821,856

 

$

1,661,513

 


 2013 2012
Audit Fees (1)$1,972,696
 $1,772,129
Audit-Related Fees (2)115,706
 258,357
Total Fees$2,088,402
 $2,030,486
(1)Fees for audit services billed in 20112013 and 20102012 consisted of audits of annual financial statements, comfort letters, statutory and regulatory audits, consents and other services related to SEC filings, and accounting research.

(2)Fees primarily for employee benefit plan audits and, in 2012, for 2011 and 2010.

145non-statutory audit services.


155





ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)                                 The following documents are filed or furnished as a part of this Form 10-K:

(1)                                 Financial Statements and Schedules:

The Report of Independent Registered Public Accounting Firm on the financial statements for each of SCANA and SCE&G areis listed under Item 8 herein.

The financial statements and supplementary financial data filed as part of this report for SCANA and SCE&G are listed under Item 8 herein.

The financial statement schedules "Schedule II - Valuation and Qualifying Accounts" filed as part of this report for SCANA and SCE&G are included below.

(2)                                 Exhibits

Exhibits required to be filed or furnished with this Annual Report on Form 10-K are listed in the Exhibit Index following the signature page. Certain of such exhibits which have heretofore been filed with the SEC and which are designated by reference to their exhibit number in prior filings are incorporated herein by reference and made a part hereof.

Pursuant to Rule 15d-21 promulgated under the Securities Exchange Act of 1934, the annual report for SCANA’s employee stock purchase plan will be furnished under cover of Form 11-K to the SEC when the information becomes available.

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% 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.

146



156



Table of Contents

Schedule II—Valuation and Qualifying Accounts

(in millions)

 

 

 

 

Additions

 

 

 

 

 

Description

 

Beginning
Balance

 

Charged to
Income

 

Charged to
Other
Accounts

 

Deductions
from
Reserves

 

Ending
Balance

 

SCANA:

 

 

 

 

 

 

 

 

 

 

 

Reserves deducted from related assets on the balance sheet:

 

 

 

 

 

 

 

 

 

 

 

Uncollectible accounts

 

 

 

 

 

 

 

 

 

 

 

2011

 

$

9

 

$

17

 

 

$

20

 

$

6

 

2010

 

9

 

28

 

 

28

 

9

 

2009

 

11

 

17

 

 

19

 

9

 

Reserves other than those deducted from assets on the balance sheet:

 

 

 

 

 

 

 

 

 

 

 

Reserve for injuries and damages

 

 

 

 

 

 

 

 

 

 

 

2011

 

$

5

 

$

4

 

 

$

3

 

$

6

 

2010

 

7

 

1

 

 

3

 

5

 

2009

 

6

 

4

 

 

3

 

7

 

 

 

 

 

 

 

 

 

 

 

 

 

SCE&G:

 

 

 

 

 

 

 

 

 

 

 

Reserves deducted from related assets on the balance sheet:

 

 

 

 

 

 

 

 

 

 

 

Uncollectible accounts

 

 

 

 

 

 

 

 

 

 

 

2011

 

$

3

 

$

6

 

 

$

6

 

$

3

 

2010

 

3

 

6

 

 

6

 

3

 

2009

 

3

 

6

 

 

6

 

3

 

Reserves other than those deducted from assets on the balance sheet:

 

 

 

 

 

 

 

 

 

 

 

Reserve for injuries and damages

 

 

 

 

 

 

 

 

 

 

 

2011

 

$

4

 

$

2

 

 

$

2

 

$

4

 

2010

 

5

 

1

 

 

2

 

4

 

2009

 

5

 

3

 

 

3

 

5

 

147

    Additions    
Description 
Beginning
Balance
 
Charged to
Income
 
Charged to
Other
Accounts
 
Deductions
from
Reserves
 
Ending
Balance
SCANA:  
  
  
  
  
Reserves deducted from related assets on the balance sheet:  
  
  
  
  
Uncollectible accounts  
  
  
  
  
2013 $7
 $13
 
 $14
 $6
2012 6
 14
 
 13
 7
2011 9
 17
 
 20
 6
Reserves other than those deducted from assets on the balance sheet:  
  
  
  
  
Reserve for injuries and damages  
  
  
  
  
2013 $6
 $4
 
 $4
 $6
2012 6
 4
 
 4
 6
2011 5
 4
 
 3
 6
           
SCE&G:  
  
  
  
  
Reserves deducted from related assets on the balance sheet:  
  
  
  
  
Uncollectible accounts  
  
  
  
  
2013 $3
 $7
 
 $7
 $3
2012 3
 6
 
 6
 3
2011 3
 6
 
 6
 3
Reserves other than those deducted from assets on the balance sheet:  
  
  
  
  
Reserve for injuries and damages  
  
  
  
  
2013 $5
 $3
 
 $3
 $5
2012 4
 3
 
 2
 5
2011 4
 2
 
 2
 4


157




Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

SCANA CORPORATION

BY:

BY:/s/ K. B. MARSH

Marsh

K. B. Marsh, Chairman of the Board, President, Chief Executive Officer, Chief Operating Officer and Director

DATE:

February 29, 2012

28, 2014

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to the registrant and any subsidiaries thereof.

/s/ K. B. MARSH

Marsh

K. B. Marsh, Chairman of the Board, President, Chief Executive Officer, Chief Operating Officer and Director

(Principal Executive Officer)

/s/ J. E. ADDISON

Addison

J. E. Addison
Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

/s/ J. E. SWAN,Swan, IV

J. E. Swan, IV
Controller

(Principal Accounting Officer)

Other Directors*:

B. L. Amick

J. M. Micali

J. A. Bennett

L. M. Miller

S.J. F. A. Decker

V. Cecil

J. W. Roquemore

D. M. Hagood

M. K. Sloan

J. W. Martin, III

H. C. Stowe

J. M. MicaliA. Trujillo



*                                        Signed on behalf of each of these persons by Ronald T. Lindsay, Attorney-in-Fact

DATE: February 29, 2012

14828, 2014



158




Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries or consolidated affiliates thereof.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

BY:

/s/ K. B. MARSH

Marsh

K. B. Marsh, Chairman of the Board, Chief Executive Officer and Director

DATE:

February 29, 2012

28, 2014

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to the registrant and any subsidiaries or consolidated affiliates thereof.

/s/ K. B. MARSH

Marsh

K. B. Marsh, Chairman of the Board, Chief Executive Officer and Director

(Principal Executive Officer)

/s/ J. E. ADDISON

Addison

J. E. Addison
Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

/s/ J. E. SWAN,Swan, IV

J. E. Swan, IV
Controller

(Principal Accounting Officer)

Other Directors*:

B. L. Amick

J. A. Bennett

J. W. Roquemore

D. M. HagoodM. K. Sloan
J. M. MicaliH. C. Stowe
L. M. Miller

J. A. Bennett

J. W. Roquemore

S. A. Decker

M. K. Sloan

D. M. Hagood

H. C. Stowe

J. M. Micali



*                                        Signed on behalf of each of these persons by Ronald T. Lindsay, Attorney-in-Fact


DATE: February 29, 2012

14928, 2014


159




Table of Contents

EXHIBIT INDEX

Exhibit

Exhibit
Applicable to
Form 10-K of

No.

SCANA

SCE&G

Description

3.01


X

X

Restated Articles of Incorporation of SCANA, Corporation, 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

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

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

3.04

X

Restated Articles of Incorporation of South Carolina Electric & Gas Company,SCE&G, as adopted on December 30, 2009 (Filed as Exhibit 1 to Form 8-A (File NumberNo. 000-53860) and incorporated by reference herein)

3.05


X

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

3.06

X

By-Laws of SCE&G as revised and amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460 and incorporated by reference herein)

4.01


X

X

4.01

X

X

Articles of Exchange of South Carolina Electric & Gas CompanySCE&G and SCANA Corporation (Filed as Exhibit 4-A to Post-Effective Amendment No. 1 to Registration Statement No. 2-90438 and incorporated by reference herein)

4.02


X

4.02

X

Indenture dated as of November 1, 1989 between SCANA Corporation and The Bank of New York Mellon Trust Company, N. A. (successor to The Bank of New York), as Trustee (Filed as Exhibit 4-A to Registration No. 33-32107 and incorporated by reference herein)

4.03


X

4.03

X

First Supplemental Indenture dated as of November 1, 2009 to Indenture dated as of November 1, 1989 between SCANA Corporation and The Bank of New York Mellon Trust Company, N.A. (successor to The Bank of New York), as Trustee (Filed as Exhibit 99.01 to Registration Statement No. 333-174796 and incorporated by reference herein)

4.04


X

4.04

X

Junior Subordinated Indenture dated as of November 1, 2009 between SCANA Corporation and U.S. Bank National Association, as Trustee (Filed as Exhibit 99.02 to Registration Statement No. 333-174796 and incorporated by reference herein)

4.05


X

4.05

X

First Supplemental Indenture to Junior Subordinated Indenture referred to in Exhibit 4.04 dated as of November 1, 2009 (Filed as Exhibit 99.03 to Registration Statement No. 333-174796 and incorporated by reference herein)

4.06


X

4.06

X

Indenture dated as of April 1, 1993 from South Carolina Electric & Gas CompanySCE&G to The Bank of New York Mellon Trust Company, N. A. (as successor to NationsBank of Georgia, National Association), as Trustee (Filed as Exhibit 4-F to Registration Statement No. 33-49421 and incorporated by reference herein)

4.07


X

4.07

X

First Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421 and incorporated by reference herein)

4.08


X

4.08

X

Second Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955 and incorporated by reference herein)

4.09
XThird Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of September 1, 2013 (Filed as Exhibit 4.12 to Post-Effective Amendment to Registration Statement No. 333-184426-01 and incorporated by reference herein)

150


160




Exhibit

Applicable to
Form 10-K of

No.

SCANA

SCE&G

Description

10.01


X

X

10.01

X

X

Engineering, Procurement and Construction Agreement, dated May 23, 2008, between South Carolina Electric & Gas Company,SCE&G, for itself and as Agent for the South Carolina Public Service Authority and a Consortium consisting of Westinghouse Electric Company LLC and Stone & Webster, Inc. (portions of the exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended) (Filed as Exhibit 10.01 to Form 10-Q/A for the quarter ended June 30, 2008 (File No. 001-08809 (SCANA); File No. 001-03375 (SCE&G)) and incorporated by reference herein)

10.02


X

X

10.02

X

X

Contract for AP1000 Fuel Fabrication and Related Services between Westinghouse Electric Company LLC and South Carolina Electric & Gas CompanySCE&G for V. C. Summer AP1000 Nuclear Plant Units 2 & 3 (portions of the exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended) (Filed as Exhibit 10.01 to Form 10-Q/A for the quarter ended June 30, 2011 (File No. 001-08809 (SCANA); (File No. 001-03375 (SCE&G)) and incorporated by reference herein)

*10.03


X

X

*10.03

X

X

SCANA Executive Deferred Compensation Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.04 to Registration Statement No. 333-174796 and incorporated by reference herein)

*10.04


X

X

*10.04

X

X

SCANA Supplemental Executive Retirement Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.05 to Registration Statement No. 333-174796 and incorporated by reference herein)

*10.05


X

X

*10.05

X

X

SCANA Director Compensation and Deferral Plan (including amendments through April 21, 2011) (Filed as Exhibit 4.05 to Registration Statement No. 333-174796 and incorporated by reference herein)

*10.06


X

X

*10.06

X

X

SCANA Long-Term Equity Compensation Plan as amended and restated (including amendments through December 31, 2009) (Filed as Exhibit 99.06 to Registration Statement No. 333-174796 and incorporated by reference herein)

*10.07


X

X

*10.07

X

X

SCANA Supplementary Executive Benefit Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.07 to Registration Statement No. 333-174796 and incorporated by reference herein)

*10.08


X

X

*10.08

X

X

SCANA Short-Term Annual Incentive Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.08 to Registration Statement No. 333-174796 and incorporated by reference herein)

*10.09


X

X

*10.09

X

X

SCANA Supplementary Key Executive Severance Benefits Plan (including amendments through December 31, 2009) (Filed as Exhibit 99.09 to Registration Statement No. 333-174796 and incorporated by reference herein)

*10.10


X

X

*10.10

X

X

Description of SCANA Whole Life Option (Filed as Exhibit 10-F for the year ended December 31, 1991, under cover of Form SE Filed(File No. 1-8809001-08809 (SCANA); (File No. 001-03375 (SCE&G)) and incorporated by reference herein)

10.11


X

10.11

X

Service Agreement between SCE&G and SCANA Services, Inc., effective January 1, 2004 (Filed as Exhibit 99.10 to Registration Statement No. 333-174796 and incorporated by reference herein)

10.12


X

Form of Indemnification Agreement (Filed as Exhibit 10.01 to Form 10-Q dated June 30, 2012 (File No. 001-08809) and incorporated by reference herein)

12.01

10.13


X

X

Amended and Restated Five-Year Credit Agreement dated as of October 25, 2012, by and among SCANA; the lenders identified therein; Wells Fargo Bank, National Association, as Issuing Bank, Swingline Lender and Agent; Bank of America, N.A. and Morgan Stanley Senior Funding, Inc., as Co-Syndication Agents and JPMorgan Chase Bank, N.A., Mizuho Corporation Bank, LTD. and TD Bank N.A., as Documentation Agents (Filed as Exhibit 99.1 to Form 8-K on October 30, 2012 (File No. 001-08809) and incorporated by reference herein)
10.14
XXAmended and Restated Five-Year Credit Agreement dated as of October 25, 2012, by and among SCE&G; the lenders identified therein; Wells Fargo Bank, National Association, as Issuing Bank, Swingline Lender and Agent; Bank of America, N.A. and Morgan Stanley Senior Funding, Inc., as Co-Syndication Agents; and Credit Suisse AG, Cayman Islands Branch and UBS Loan Finance LLC, as Documentation Agents (Filed as Exhibit 99.2 to Form 8-K on October 30, 2012 (File No. 001-08809 (SCANA); File No. 001-00375 (SCE&G)) and incorporated by reference herein)

161



10.15
XXThree-Year Credit Agreement dated as of October 25, 2012, by and among SCE&G; the lenders identified therein; Wells Fargo Bank, National Association, as Issuing Bank, Swingline Lender and Agent; Bank of America, N.A. and Morgan Stanley Senior Funding, Inc., as Co-Syndication Agents; and Credit Suisse AG, Cayman Islands Branch and UBS Loan Finance LLC, as Documentation Agents (Filed as Exhibit 99.3 to Form 8-K on October 30, 2012 (File No. 001-08809 (SCANA); File No. 001-03375 (SCE&G)) and incorporated by reference herein)
10.16
XXAmended and Restated Five-Year Credit Agreement dated as of October 25, 2012, by and among Fuel Company; the lenders identified therein; Wells Fargo Bank, National Association, as Swingline Lender and Agent; Bank of America, N.A. and Morgan Stanley Senior Funding, Inc., as Co-Syndication Agents; and JPMorgan Chase Bank, N.A., Mizuho Corporation Bank, LTD. and TD Bank N.A., as Documentation Agents (Filed as Exhibit 99.4 to Form 8-K on October 30, 2012 (File No. 001-08809 (SCANA); (File No. 001-03375 (SCE&G)) and incorporated by reference herein)
10.17
XAmended and Restated Five-Year Credit Agreement dated as of October 25, 2012, by and among PSNC Energy; the lenders identified therein; Wells Fargo Bank, National Association, as Issuing Bank, Swingline Lender and Agent; Bank of America, N.A. and Morgan Stanley Senior Funding, Inc., as Co-Syndication Agents; and JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, LTD. and TD Bank N.A., as Documentation Agents (Filed as Exhibit 99.5 to Form 8-K on October 30, 2012 (File No. 001-08809) and incorporated by reference herein)
12.01
XXStatement Re Computation of Ratios (Filed herewith)

21.01


X

12.02

X

Statement Re Computation of Ratios (Filed herewith)

151



Table of Contents

Exhibit

Applicable to
Form 10-K of

No.

SCANA

SCE&G

Description

21.01

X

Subsidiaries of the registrant (Filed herewith under the heading “Corporate Structure”Structure and Organization” in Part I, Item I of this Form 10-K and incorporated by reference herein)

23.01


X

23.01

X

Consents of Experts and Counsel (Consent of Independent Registered Public Accounting Firm) (Filed herewith)

23.02


X

23.02

X

Consents of Experts and Counsel (Consent of Independent Registered Public Accounting Firm) (Filed herewith)

24.01


X

24.01

X

Power of Attorney (Filed herewith)

24.02


X

24.02

X

Power of Attorney (Filed herewith)

31.01


X

31.01

X

Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)

31.02


X

31.02

X

Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)

31.03


X

31.03

X

Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)

31.04


X

31.04

X

Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)

32.01


X

32.01

X

Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

32.02


X

32.02

X

Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

32.03


X

32.03

X

Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

32.04


X

32.04

X

Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

101. INS**

X

X

XBRL Instance Document

101. SCH**

X

X

XBRL Taxonomy Extension Schema

101. CAL**

X

X

XBRL Taxonomy Extension Calculation Linkbase


162



101. DEF**

X

X

XBRL Taxonomy Extension Definition Linkbase

101. LAB**

X

X

XBRL Taxonomy Extension Label Linkbase

101. PRE**

X

X

XBRL Taxonomy Extension Presentation Linkbase


*

*Management Contract or Compensatory Plan or Arrangement

**

**

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

152




163