UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

SCHEDULE 14A INFORMATION

Proxy Statement Pursuant to Section 14(a) of the

Securities Exchange Act of 1934

(Amendment No.    )

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SCANA CORPORATION
(Name of registrant as specified in its charter)
(Name of person(s) filing proxy statement, if other than the registrant)
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Your VOTE is Important

SCANA Corporation 2014 Proxy Materials

Chairman’s Letter and 2013 Highlights,

Notice of 2014 Annual Meeting,

Proxy Statement for Annual Meeting,

Annual Financial Statements,

Management’s Discussion and

    Analysis and Related Annual

    Report Information

TABLE OF CONTENTS

	Page
CHAIRMAN’S LETTER AND 2013 HIGHLIGHTS
NOTICE OF 2014 ANNUAL MEETING
PROXY STATEMENT
INFORMATION ABOUT THE SOLICITATION OF PROXIES		1
MATTERS TO BE CONSIDERED AT THE 2014 ANNUAL MEETING		1
VOTING PROCEDURES		2
PROPOSAL 1 — ELECTION OF DIRECTORS		5
NOMINEES FOR DIRECTORS		6
CONTINUING DIRECTORS		7
ADDITIONAL INFORMATION ABOUT EXPERIENCE AND QUALIFICATION OF DIRECTORS AND NOMINEES		9
BOARD MEETINGS — COMMITTEES OF THE BOARD		11
GOVERNANCE INFORMATION		13
RELATED PARTY TRANSACTIONS		18
SHARE OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		19
EXECUTIVE COMPENSATION		21
Compensation Committee Processes and Procedures		21
Compensation Committee Interlocks and Insider Participation		22
Compensation Risk Assessment		22
Compensation Discussion and Analysis		22
Compensation Committee Report		37
Summary Compensation Table		38
2013 Grants of Plan-Based Awards		39
Outstanding Equity Awards at 2013 Fiscal Year-End		40
2013 Option Exercises and Stock Vested		41
Pension Benefits		42
2013 Nonqualified Deferred Compensation		43
Potential Payments Upon Termination or Change in Control		45
DIRECTOR COMPENSATION		53
2013 Director Compensation Table		56
AUDIT COMMITTEE REPORT		57
PROPOSAL 2 — APPROVAL OF THE APPOINTMENT OF THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		58
PROPOSAL 3  —APPROVAL OF BOARD-PROPOSED AMENDMENTS TO ARTICLE 8 OF OUR ARTICLES OF INCORPORATION TO DECLASSIFY THE BOARD OF DIRECTORS AND PROVIDE FOR THE ANNUAL ELECTION OF ALL DIRECTORS		59
PROPOSAL 4 — ADVISORY (NON-BINDING) VOTE TO APPROVE EXECUTIVE COMPENSATION		61
OTHER INFORMATION		62

FINANCIAL APPENDIX

Index to Annual Financial Statements, Management’s Discussion and Analysis and Related Annual Report Information

March 24, 2014

Dear Shareholders:

You are cordially invited to attend the 2014 Annual Meeting of Shareholders to be held at 9:00 a.m., Eastern Daylight Time, on Thursday, April 24, 2014. The meeting will be held at Leaside, 100 East Exchange Place, Columbia, South Carolina 29209. Directions are on the back of the ticket and on page 63 of this Proxy Statement. An admission ticket is required and is enclosed as part of your proxy card if you were a shareholder of record on the record date, March 4, 2014. If you hold your shares through a broker, you must provide proof of ownership on the record date in order to attend the meeting.

At our 2014 Annual Meeting of Shareholders I will provide a brief report on SCANA’s 2013 business results. I welcome the opportunity to discuss some of our accomplishments for 2013, as well as some of our challenges for 2014 and beyond. I hope you will be able to join us at our Annual Meeting, but for those of you who will be unable to attend the meeting, I would like to highlight here some of our most significant accomplishments over the last year, which include:

• We exceeded our publicly disclosed 2013 growth in earnings per share target goal of 4.5% by achieving earnings per share growth of 6.3% for the second consecutive year;

• Our operations and maintenance expenses were under budget by over $12 million, with no resulting negative impact on our commitment to safety, reliability, or customer service;

• In March 2013, we achieved an important and difficult milestone by being the first company in 30 years to complete a nuclear island basemat concrete pour in the United States. The historic milestone was achieved for V.C. Summer Station Unit 2 and was an accomplishment for our employees, our shareholders, and the nuclear industry. In November 2013, we also poured basemat concrete at V.C. Summer Station Unit 3;

• We successfully reduced and redeployed certain of our workforce while pursuing important initiatives such as succession development, renewable fuels, and our new nuclear construction project. Our employees recognize the challenges facing our Company and the need for such workforce changes and have supported the efforts with no negative impact to safety, reliability, or customer service; and

• Our Board of Directors considered the positive results of 2013, along with the confidence the Company has in its long-term strategy to grow dividends fairly consistent with earnings growth, in making its determination to increase our common stock dividend rate. In February 2014, our Board of Directors raised the quarterly cash dividend on the Company’s common stock to 52 ¹/₂ cents per share from 50 ³/₄ cents per share, an increase of 3.5%. This action increases the indicated annual dividend rate to $2.10 per share from $2.03 per share.

Also, importantly, our 2014 Proxy Statement includes a Board proposal for the declassification of our Board of Directors. Our Board is committed to strong corporate governance practices. In considering the 2012, 2013 and 2014 shareholder proposals we received, as well as the growing support of institutional investor groups for the annual election of directors, the Board took into account the advantages and disadvantages of a classified board. After carefully reviewing the various considerations, the Board decided to propose an amendment to our Articles of Incorporation to declassify the Board and to submit it to our shareholders with a recommendation that they vote in favor of the amendment.

Enclosed are the Notice of 2014 Annual Meeting identifying the four proposals that will be presented at the meeting, and SCANA’s Proxy Statement and form of proxy for the meeting. The approximate date of mailing for this Proxy Statement and form of proxy is March 24, 2014. We are including SCANA’s annual consolidated financial statements, management’s discussion and analysis of financial condition and results of operations and related annual report information as an appendix to the Proxy Statement.

• If you vote by mail and plan to attend the meeting, please indicate your intention to do so on your proxy card. If you vote by telephone or through the Internet, please follow the instructions to indicate that you plan to attend the 2014 Annual Meeting.

• If you will need special assistance at the meeting, please contact the Office of the Corporate Secretary, at 220 Operation Way, Mail Code D133, Cayce, South Carolina 29033, or call 803-217-7568 no later than Thursday, April 17, 2014.

• Refreshments will be served beginning at 8:00 a.m.

Your vote is important. We encourage you to read the Proxy Statement and vote your shares as soon as possible. Please vote today either electronically by telephone or through the Internet, or by signing, dating and mailing your proxy card or broker’s voting instruction form in the envelope enclosed. Telephone and Internet voting permits you to vote at your convenience, 24 hours a day, seven days a week. Detailed voting instructions are included on the back of your proxy card or broker’s voting instruction form.

Sincerely,

Kevin B. Marsh

Chairman of the Board, President and Chief Executive Officer

NOTICE OF ANNUAL MEETING

Meeting Date:	Thursday, April 24, 2014
Meeting Time:	9:00 a.m., Eastern Daylight Time
Meeting Place:	Leaside 100 East Exchange Place Columbia, South Carolina 29209
Meeting Record Date:	March 4, 2014
Meeting Agenda:	1)   Election of three Class III Directors 2)   Approval of the appointment of the independent registered public accounting firm 3)   Approval of Board-proposed amendments to Article 8 of our Articles of Incorporation to declassify the Board of Directors and provide for the annual election of all directors 4)   Advisory (non-binding) vote on executive compensation

Shareholder List

Upon written request by a shareholder, a list of shareholders entitled to vote at the meeting will be available for inspection at SCANA’s Corporate Headquarters, 100 SCANA Parkway, Cayce, South Carolina 29033, during business hours from March 24, 2014 through the date of the meeting.

Admission to the Meeting

An admission ticket or proof of share ownership as of the record date is required. If you plan to use the admission ticket, please remember to detach it from your proxy card before mailing your proxy card. If you hold your shares through a broker or other nominee, you must provide proof of ownership by bringing either a copy of the voting instruction card provided by your broker or a brokerage statement showing your share ownership as of March 4, 2014. Audio or visual recording, and related equipment, is strictly prohibited without SCANA’s prior written approval.

By Order of the Board of Directors,

Gina Champion

Corporate Secretary

SCANA Corporation

100 SCANA Parkway

Cayce, South Carolina 29033

PROXY STATEMENT

INFORMATION ABOUT THE SOLICITATION OF PROXIES

We are providing these proxy materials in connection with the solicitation by the Board of Directors of SCANA Corporation (“SCANA,” the “Company,” “we” or “us”), a South Carolina corporation, of proxies to be voted at our 2014 Annual Meeting of Shareholders (the “2014 Annual Meeting”), which will be held at 9:00 a.m., Eastern Daylight Time on Thursday, April 24, 2014, and at any adjournment or postponement of the meeting. The meeting will be held at Leaside, 100 East Exchange Place, Columbia, South Carolina 29209. These proxy materials are first being mailed to shareholders of record on or about March 24, 2014.

MATTERS TO BE CONSIDERED AT THE ANNUAL MEETING

Proposal 1 — Election of Directors

Three Class III Directors, whose terms expire at the 2014 Annual Meeting, have been nominated for reelection to serve until the Annual Meeting of Shareholders in 2017. Please see “Proposal 1 — Election of Directors” beginning on page 5.

Proposal 2 — Approval of the Appointment of the Independent Registered Public Accounting Firm

The Board is proposing that shareholders approve the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for the year ended December 31, 2014. Please see “Proposal 2 — Approval of the Appointment of the Independent Registered Public Accounting Firm” beginning on page 58.

Proposal 3 — Approval of Board-Proposed Amendments to Article 8 of our Articles of Incorporation to Declassify the Board of Directors and Provide for the Annual Election of All Directors

The Board is proposing amendments to Article 8 of our Articles of Incorporation to declassify our Board of Directors and provide for the annual election of all directors. Please see “Proposal 3 — Approval of Board-Proposed Amendments to Article 8 of our Articles of Incorporation to Declassify the Board of Directors and Provide for the Annual Election of All Directors” beginning on page 59.

Proposal 4 — Advisory (non-binding) Vote to Approve Executive Compensation

Pursuant to the rules of the Securities and Exchange Commission, you will have the opportunity to vote on an advisory (non-binding) proposal to approve the compensation paid to our named executive officers as disclosed in the “Executive Compensation” section of this proxy statement. As discussed in that section, our compensation program is designed to reward senior executive officers for their individual and collective performance and for our collective performance in achieving target goals for earnings per share and total shareholder return and other annual and long-term business objectives. We believe these goals and objectives are well-aligned with shareholder interests, and are fair to us and to our executives. Although the results of this vote are not binding on our Board of Directors, the Board will review them, and may take them into account in making future executive compensation decisions. Please see “Proposal 4 — Advisory (non-binding) Vote to Approve Executive Compensation” beginning on page 61.

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VOTING PROCEDURES

Your Vote is Important

Whether or not you plan to attend the Annual Meeting, please vote your shares as soon as possible.

Who May Vote

You will only be entitled to vote at the 2014 Annual Meeting if our records show that you were a shareholder of record on March 4, 2014, the record date, or, if you hold your shares in street name, you present proof of ownership and appropriate voting documents from the record shareholder.

Voting Shares Held Directly

If you hold your shares directly, you may vote by proxy or in person at the meeting. To vote by proxy, you may select one of the following options: telephone, Internet or mail.

Vote by Telephone:

You may vote your shares by touch-tone telephone using the toll-free number shown on the back of your proxy card. You must have a touch-tone telephone to use this option. Telephone voting is available 24 hours a day, seven days a week. Clear and simple voice prompts allow you to vote your shares and confirm that your instructions have been properly recorded. If you vote by telephone, please DO NOT return your proxy card.

Vote through the Internet:

You may vote through the Internet. The website for Internet voting is shown on the back of your proxy card. Internet voting is available 24 hours a day, seven days a week. When you vote through the Internet, you will be given the opportunity to confirm that your instructions have been properly recorded. If you vote through the Internet, please DO NOT return your proxy card.

Vote by Mail:

If you choose to vote by mail, please mark the enclosed proxy card, date and sign it, detach your meeting admission ticket and return your proxy card in the enclosed postage-paid envelope.

Actions to be Taken by the Proxies

If you hold your shares directly and indicate your voting choices on your proxy card, the persons identified as proxies on the accompanying proxy card will vote your shares according to your instructions. If your proxy card is signed and returned without specifying choices, the proxies intend to vote your shares FOR all of the Board of Directors’ nominees, FOR the approval of the appointment of the independent registered public accounting firm, FOR Proposal 3 relating to the Board-proposed amendments to Article 8 of our Articles of Incorporation to declassify the Board of Directors and provide for the annual election of all directors, and FOR Proposal 4 regarding the approval of executive compensation.

Directing the Vote of Shares Held in Street Name

If you hold shares in street name, you may direct your vote by submitting your voting instructions to your broker or nominee. Please refer to the voting instructions provided by your broker or nominee. Unless you provide voting instructions, your broker is not permitted to vote your shares on the election of directors or on Proposals 3 or 4. Therefore, to be sure your shares are voted, please instruct your broker or other nominee as to how you wish them to vote.

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Changing or Revoking Your Proxy Instructions

You may change or revoke your proxy instructions at any time prior to the vote at the Annual Meeting. If you hold your shares directly in your name, you may accomplish this by granting a new proxy (by telephone, Internet or mail) bearing a later date (which automatically revokes the earlier proxy) or by attending the Annual Meeting and voting in person. Attendance at the meeting will not cause your previously granted proxy to be revoked unless you specifically so request. If you hold your shares in street name, you may change or revoke your proxy instructions by properly submitting new voting instructions to your broker or nominee.

Voting By Savings Plan Participants

If you own shares of SCANA common stock as a participant in the SCANA Corporation Stock Purchase-Savings Plan, you will receive a proxy card that covers only your Plan shares. Proxies executed by Plan participants will serve as voting instructions to the Plan’s trustee. If you do not vote your SCANA Corporation Stock Purchase-Savings Plan shares, your shares will be voted proportionally to the Plan shares voted. As a result of this proportional voting, if only a small percentage of participant shares are voted, the wishes of those participants would determine the vote by the Plan’s trustee. Accordingly, the greater the number of participant shares for which participants execute proxies, the more representative the Plan trustee’s vote will be.

Voting at the Annual Meeting

The method by which you vote will not limit your right to vote at the Annual Meeting if you decide to attend in person. However, if you wish to vote at the meeting and your shares are held in the name of a bank, broker or other holder of record, you must obtain a proxy executed in your favor from the holder of record prior to the meeting. Directions to the location of the Annual Meeting are on the back of the proxy card included with this mailing and on page 63.

Quorum and Method of Counting Votes

At the close of business on the record date, March 4, 2014, there were 141,145,971 shares of SCANA common stock outstanding and entitled to vote at the Annual Meeting. Each share is entitled to one vote on each proposal.

The presence, in person or by proxy, of the holders of a majority of the shares entitled to vote at the Annual Meeting is necessary to constitute a quorum. Abstentions, “withheld” votes and broker “non-votes” are counted as present and entitled to vote for purposes of determining a quorum. A broker “non-vote” occurs when a nominee holding shares for a beneficial owner does not vote on a particular proposal because the nominee has not received instructions from the beneficial owner and either (i) does not have discretionary voting power for that particular proposal, or (ii) chooses not to vote the shares.

If you hold your shares in street name, the broker or nominee is permitted to vote your shares on the approval of the appointment of Deloitte & Touche LLP as our independent registered public accounting firm even if the broker or nominee does not receive voting instructions from you. However, a broker is not permitted to vote your shares on the election of directors or on Proposals 3 or 4 unless you provide voting instructions. Accordingly, if you do not return a broker voting instruction card, or if you return a broker voting instruction card that does not indicate how you want your broker to vote on election of directors or on Proposal 3 or 4, a broker “non-vote” will occur as to those matters. Therefore, it is very important that you provide your broker with voting instructions if your shares are held in street name.

Vote Required

Proposal 1 — Election of Directors

The affirmative vote of a plurality of the votes cast is required for the election of directors, subject to the Board of Directors’ policy regarding resignations for directors who do not receive a majority of “FOR” votes. “Plurality” means that if there were more nominees than positions to be filled, the individuals who received the largest number of votes cast for directors would be elected as directors. Because there are the same number of nominees as positions to be filled, we expect all nominees to be elected. Votes indicated as “withheld” and broker “non-votes” will not be cast for nominees and will have no effect on the outcome of the election subject only to the majority voting policy for Directors as mentioned above. If you hold your shares in street name and fail to instruct your broker how to vote, a broker non-vote on election of directors will occur with respect to your shares.

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The Board knows of no reason why any of the nominees for director named herein would at the time of election be unable to serve. In the event, however, that any nominee named should, prior to the election, become unable to serve as a director, your proxy will be voted for such other person or persons as the Board may recommend.

Proposal 2 — Approval of the Appointment of the Independent Registered Public Accounting Firm

The appointment of Deloitte & Touche LLP will be approved if more shares vote for approval than vote against. Accordingly, abstentions and broker “non-votes” will have no effect on the results. If you hold your shares in street name and fail to instruct your broker how to vote, your broker will, nonetheless, have discretionary authority to vote your shares if it chooses to do so.

Proposal 3 — Approval of Board-Proposed Amendments to Article 8 of our Articles of Incorporation to Declassify the Board of Directors and Provide for the Annual Election of All Directors

The proposal to amend our Articles of Incorporation to declassify the Board of Directors and provide for the annual election of all directors requires the affirmative vote of at least 80% of all outstanding shares of our common stock. Votes indicated as “abstain” and broker “non-votes” will have the effect of votes against the proposal. If you hold your shares in street name and fail to instruct your broker how to vote, a broker “non-vote” will occur with respect to your shares.

Proposal 4 — Advisory (non-binding) Vote to Approve Executive Compensation

This proposal is advisory and non-binding on us and on our Board of Directors. Marking the proxy card or your broker voting instructions “For” indicates support; marking the proxy card or your broker voting instructions “Against” indicates lack of support. You may also abstain by marking the “Abstain” box on the proxy card or your broker voting instructions. If you hold your shares in street name and fail to instruct your broker how to vote, a broker “non-vote” will occur with respect to your shares.

Other Business

The Board knows of no other matters to be presented for shareholder action at the Annual Meeting. If other matters are properly brought before the Annual Meeting, the persons identified as proxies on the accompanying proxy card intend to vote the shares represented by proxies in accordance with their best judgment.

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PROPOSAL 1 — ELECTION OF DIRECTORS

Effective at the 2014 Annual Meeting of Shareholders, the Board has set the number of directors at ten. The Board is divided into three classes with the members of each class usually serving a three-year term. The terms of the Class III Directors will expire at the 2014 Annual Meeting. The Board has decided to nominate the existing Class III Directors, Messrs. Cecil, Hagood, and Trujillo, for reelection at the 2014 Annual Meeting to serve until the 2017 annual meeting of shareholders, or until their successors are elected and have qualified to serve.

In October 2012, the Nominating and Governance Committee directed management to retain an independent executive recruiting firm to assist the Committee in identifying and evaluating potential director candidates who met the director qualification criteria discussed under “Director Qualification Criteria” on page 15, as well as certain additional specific criteria including geographic location, financial expertise, and diversity. The Board of Directors provided 10 potential candidates to the recruitment firm to be considered and screened in the same manner as the recruiter’s potential candidates. After an extensive search process and background review by the recruiting firm, Messrs. Cecil and Trujillo were among approximately 60 potential candidates recommended by the recruiting firm as meeting the director qualification criteria, as well as the more specific criteria discussed with respect to each of them under “Additional Information about Experience and Qualification of Directors and Nominees” on page 9. After an initial screening by the Nominating and Governance Committee of the candidates, the Committee recommended several candidates for interviews by our Board of Directors. A total of five candidates were interviewed by the full Board, with the exception of one Board member who was not available to participate in the interviews. After further deliberation, the Board of Directors directed the firm to conduct extensive background investigations on the selected candidates, and after a review of the results of the background investigations, the Board of Directors elected Messrs. Cecil and Trujillo on October 10, 2013 to serve as Class III Directors until the 2014 Annual Meeting of Shareholders.

The Board of Directors unanimously recommends a vote FOR all of its director nominees.

Information about Directors and Nominees

The information set forth on the following pages about the nominees and continuing directors has been furnished to us by such persons. Each of the directors, with the exception of Messrs. Cecil and Trujillo, is also a director of our subsidiary, South Carolina Electric & Gas Company. There are no family relationships among any of our directors, director nominees or executive officers.

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NOMINEES FOR DIRECTORS

Class III Directors — Terms to Expire at the Annual Meeting in 2017

	John F.A.V. Cecil (Age 57) Director since 2013
	Mr. Cecil has served since 1992 as President of Biltmore Farms, LLC, a fourth generation family-owned business with a primary focus on sustainable community development, including home building, residential communities, apartments, hotels, and retail properties. He currently serves on Wells Fargo Bank, N.A.’s Western North Carolina Regional Advisory Board, as well as other community and non-profit boards throughout North Carolina.
	D. Maybank Hagood (Age 52) Director since 1999
	Mr. Hagood has been Chief Executive Officer of Southern Diversified Distributors, Inc., located in Charleston, South Carolina, since 2003, and its Chairman since 2012. Southern Diversified Distributors, Inc., is the parent company of William M. Bird and Company, Inc., Southern Tile Distributors, LLC and TranSouth Logistics, LLC, providers of logistic, distribution and flooring distribution services. Mr. Hagood also has been Chief Executive Officer of William M. Bird and Company, Inc., a wholesale distributor of floor covering materials, in Charleston, South Carolina, since 1993. He served as President of William M. Bird and Company, Inc., until June 2009.
	Alfredo Trujillo (Age 54) Director since 2013
	Mr. Trujillo was appointed President and Chief Operating Officer of The Georgia Tech Foundation in July 2013. He has served as a self-employed investment fund advisor since 2007. Prior to 2007, Mr. Trujillo served as President and Chief Executive Officer of Recall Corporation, a global information management company. Since 2003, Mr. Trujillo has served on the Board of Directors of Haverty Furniture Companies, Inc.

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CONTINUING DIRECTORS

Class I Directors — Terms to Expire at the Annual Meeting in 2015

	James A. Bennett (Age 53) Director since 1997
	Mr. Bennett has been Executive Vice President and Director of Public Affairs of First Citizens Bank, located in Columbia, South Carolina, since August 2002. From May 2000 to July 2002, he was President and Chief Executive Officer of South Carolina Community Bank, in Columbia, South Carolina. Mr. Bennett serves on the board of Palmetto Baptist Hospital, which is affiliated with Palmetto Health, headquartered in Columbia, South Carolina.
	Lynne M. Miller (Age 62) Director since 1997
	Ms. Miller co-founded Environmental Strategies Corporation, an environmental consulting firm in Reston, Virginia, in 1986, and served as President from 1986 until 1995, and as Chief Executive Officer from 1995 until September 2003 when the firm was acquired by Quanta Capital Holdings, Inc., a specialty insurer, and its name was changed to Environmental Strategies Consulting LLC. She was Chief Executive Officer of Environmental Strategies Consulting LLC, a division of Quanta Technical Services LLC, from September 2003 through March 2004. From April 2004 through July 2005, she was President of Quanta Technical Services LLC. From August 2005 until her retirement in August 2006, she was a Senior Business Consultant at Quanta Capital Holdings. Since her retirement, Ms. Miller has been an environmental consultant. Ms. Miller served as a director of Adams National Bank, a subsidiary of Abigail Adams National Bancorp, Inc., in Washington, D.C. from May 1998 until October 2008.
	James W. Roquemore (Age 59) Director since 2007
	Mr. Roquemore is Chief Executive Officer and Chairman of Patten Seed Company, headquartered in Lakeland, Georgia, and General Manager of Super-Sod/Carolina, a company that produces and markets turf grass, sod and seed. He has held these positions for more than five years. Mr. Roquemore is a director of South Carolina Bank and Trust, N.A., and SCBT Financial Corporation. He has served on the Southeast Region and National boards of the Boy Scouts of America, and he is the past President and a current board member of the Palmetto Agribusiness Council.
	Maceo K. Sloan (Age 64) Director since 1997
	Mr. Sloan is Chairman, President and Chief Executive Officer of Sloan Financial Group, Inc., a financial holding company, and Chairman, Chief Executive Officer and Chief Investment Officer of both NCM Capital Management Group, Inc., and NCM Capital Advisers, Inc., investment management companies, in Durham, North Carolina. He has held these positions for more than five years. Mr. Sloan has also been the Principal Officer of the NCM Capital Investment Trust since 2007. From 2009 to 2012, Mr. Sloan was Chairman of, and since 1991 has served as a member of, the College Retirement Equities Fund (CREF) Board of Trustees. Mr. Sloan served as Chairman of the Board of M&F Bancorp, Inc., and as a director of its subsidiary, Mechanics and Farmers Bank, in Durham, North Carolina, from June 2005 until December 2008.

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CONTINUING DIRECTORS

Class II Directors — Terms to Expire at the Annual Meeting in 2016¹

	Kevin B. Marsh (Age 58) Director since 2011
	Mr. Marsh has been employed by SCANA or its subsidiaries for 30 years, and since December 2011 has served as SCANA’s Chairman of the Board and Chief Executive Officer. Since January 2011, he has also served as our President and Chief Operating Officer. He served as our Chief Financial Officer from 1996 to April 2006, and served as a Senior Vice President from 1998 to January 2011. In addition, he served as President of our principal subsidiary, South Carolina Electric & Gas Company, from April 2006 to November 2011.
	James M. Micali (Age 66) Director since 2007
	Mr. Micali was Chairman and President of Michelin North America, Inc., located in Greenville, South Carolina, from 1996 to August 2008, and he continued to consult for Michelin until October 2009. From 2008 until September 2011, he was of counsel to the law firm Ogletree Deakins, LLC in Greenville, South Carolina. Since 2008, Mr. Micali has been a Senior Advisor to, and a limited partner of, Azalea Fund III of Azalea Capital LLC (a private equity firm), also in Greenville, South Carolina. Mr. Micali has served as a director of Sonoco Products Company in Hartsville, South Carolina since 2003 and has served as their Lead Director since February 2012. Mr. Micali also serves on the board of American Tire Distributors Holding, Inc. in Charlotte, North Carolina. Mr. Micali served on the board of Lafarge North America from 2004 to 2006, and as the Chairman of the South Carolina Chamber of Commerce in 2008, and on the board of Ritchie Bros. Auctioneers in Vancouver, Canada from April 2008 until April 2012.
	Harold C. Stowe (Age 67) Director since 1999
	Mr. Stowe has served as Managing Member of Stowe-Monier Management, LLC, a private investment company, since July 2007. He retired as interim Dean of the Wall College of Business at Coastal Carolina University in Conway, South Carolina in July 2007, a position he had held since June 2006. Prior to his retirement in February 2005, Mr. Stowe served as President of Canal Holdings, LLC, a forest products company, located in Conway, South Carolina, and its predecessor company, since March 1997. Mr. Stowe also served on the board of Harris Teeter Supermarkets, Inc., formerly known as Ruddick Corporation, in Charlotte, North Carolina, from 1998 until January 2013.

¹  Mr. Joshua W. Martin, III is currently a member of Class II but is not shown above because he will reach the age of 70 in September 2014, and accordingly, his term as a director will expire in accordance with our Articles of Incorporation as of the Annual Meeting of Shareholders in 2014. The Board of Directors has reduced the size of the Board to ten effective with the retirement of Mr. Martin so that the Board will have sufficient time to consider board member recruitment.

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ADDITIONAL INFORMATION ABOUT EXPERIENCE AND QUALIFICATION OF DIRECTORS AND NOMINEES

We believe the combined business and professional experience of our directors, and their various areas of expertise, make them a useful resource to management and qualify them for service on our Board. Many of our directors, including Ms. Miller and Messrs. Bennett, Hagood, Sloan and Stowe, have served on our Board for over a decade. During their tenures, they have gained considerable institutional knowledge about our Company, its operations, and its various regulators, which has made them effective directors. Because our Company’s operations and business structure are extremely complex and highly regulated, continuity of service and the development of institutional knowledge help make our Board more efficient and effective at developing our long-range plans than it would be if there were frequent turnover in Board membership. When directors reach mandatory retirement age or otherwise leave our Board, we seek replacements who we believe will make significant contributions to our Board for a variety of reasons, including among others, business and financial experience and expertise, business and government contacts, relationship skills, industry knowledge, and diversity.

Mr. Bennett, who has served on our Board since 1997, has been a banker for over 27 years. In 1989, he became the youngest bank president in South Carolina when he was named President of Victory Savings Bank (the predecessor of South Carolina Community Bank), a position he held before joining First Citizens Bank. Mr. Bennett has been actively involved with the Columbia Urban League for more than 28 years, and served as League Chairman in 2000. Mr. Bennett serves on the boards of Palmetto Baptist Hospital, which is affiliated with Palmetto Health, and the Knight Foundation. His business experience, coupled with his tenure on our Board, makes him an effective advisor. His high visibility in communities we serve makes him an effective liaison between our Company and members of those communities.

Mr. Cecil is one of two directors added to our Board in October 2013. He was recommended to the Nominating and Governance Committee by a former director. Mr. Cecil was included in the pool of approximately 60 candidates screened by the executive recruitment firm engaged to assist the Board in its search for new directors. Mr. Cecil was selected as a nominee because of his decades of business experience within our service territory. In addition to his business expertise, he has leadership-level experience with many community-related endeavors and has also served on community and private boards within our service territory for many years. As President of Biltmore Farms, LLC, a fourth generation family-owned business with a primary focus on sustainable community development, Mr. Cecil provides the perspective of a private business owner as well as the environmental perspective of a business that seeks to balance sustainability and business growth, both of which are important to our customers and our strategic initiatives.

Mr. Hagood has served on our Board since 1999. He is a partial owner of a significant regional business and resides in our Charleston, South Carolina service territory. He brings significant community presence and business development experience to our Board. Mr. Hagood is particularly experienced in economic, environmental, and business development issues facing the manufacturing and building construction industries generally, and specifically the issues faced by manufacturers in our state.

Mr. Marsh has served on our Board since January 2011, and he has been employed by the Company or its subsidiaries in various capacities for 30 years. He currently serves as our Chairman of the Board, Chief Executive Officer, President and Chief Operating Officer. Mr. Marsh brings significant, hands-on experience to our Board having served our Company in senior operational and financial positions for almost three decades, as well as having practiced as a certified public accountant for several years prior to joining us. His vast operational and regulatory experience makes him a trusted and experienced advisor for our Board.

Mr. Micali’s combination of experience as Chairman and President of a major North American manufacturing company with significant operations in South Carolina, as an attorney, and as a director of other public companies, enables him to offer our Board and management insights into various aspects of corporate operations, governance and financial matters. His past service as Chairman of the South Carolina Chamber of Commerce has provided him with a valuable understanding of business issues facing South Carolina, as well as a large network of business, state and national government contacts, many of whom are, or may be, important resources for our Company.

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Ms. Miller, who has served on our Board since 1997, has over 20 years of environmental consulting experience. She founded a successful environmental consulting firm in Reston, Virginia, which she grew to over 180 professional staff. She sold this business in 2003, but continued to serve in various capacities with the firm and its affiliates until her retirement in 2006. Ms. Miller continues to provide services as an environmental consultant, and her experience makes her an astute advisor on the environmental issues facing our Company. Ms. Miller also served on the board of a financial institution which provided her with experience in financial and regulatory matters.

Mr. Roquemore is a past President and current board member of the Palmetto Agribusiness Council. He also served as a Co-Chairman of New Carolina which is South Carolina’s Council on Competitiveness. Mr. Roquemore is a highly successful agricultural business owner who resides in our service territory. Because agriculture is an important component of the economy in our South Carolina service area, his knowledge of this sector and his contacts are important to us. His business experience and economic development activities in our state make him an effective advisor on issues unique to us and the customers we serve. His service on the boards of a financial institution and its holding company also give him experience in financial and regulatory matters.

Mr. Sloan, who has served on our Board since 1997, is an attorney and a chartered financial analyst. His experience owning and operating investment management companies and a financial holding company have provided him with an investment background and understanding of global financial matters, all of which make him an important resource to us and to our Audit Committee. Additionally, his service with these companies has provided him with experience in a highly regulated industry, providing him with valuable instincts and insights. His experience serving on the board of a major retirement fund makes him a valuable resource to our Board as well.

Mr. Stowe has significant business experience and has served on our Board since 1999. Mr. Stowe previously served as President of Canal Industries (a forest products company) and also previously held executive and financial positions at Springs Industries. He has over 30 years of executive-level financial and business experience. Mr. Stowe’s extensive executive and financial experience has resulted in the Board designating him as an audit committee financial expert and appointing him as a past Chair of the Audit Committee.

Mr. Trujillo was also one of two additions to our Board in October 2013. He was recommended to the Nominating and Governance Committee by one of our directors and was also included in the pool of approximately 60 candidates screened by the executive recruitment firm engaged to assist the Board in its search for new directors. Mr. Trujillo was selected as a nominee because of his domestic and international business expertise in areas as diverse as aerospace engineering, document management, and academic leadership, and his multi-cultural background. Mr. Trujillo previously held the position of President and Chief Executive Officer for a global document management company, and he currently holds the position of President and Chief Operating Officer of The Georgia Tech Foundation. Additionally, Mr. Trujillo currently serves on the board of directors of another public company, which provides him with relevant board experience and perspectives on other public company best practices.

As mentioned above, five of our directors, Ms. Miller and Messrs. Cecil, Hagood, Roquemore and Sloan, are, or were prior to retirement, business owners with financial and operational experience on all levels of their businesses. Each of these directors brings a unique perspective to our Board. In addition, four of our directors, Ms. Miller and Messrs. Bennett, Roquemore and Sloan, are, or have been, directors or executive officers of banks and/or bank holding companies. This service has provided them with meaningful experience in another highly regulated industry, which provides them with valuable instincts and insights that can be translated to our industry.

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BOARD MEETINGS — COMMITTEES OF THE BOARD

The Board held eight meetings in 2013, consisting of four regular Board meetings, one teleconference meeting, one Code of Conduct and Ethics training session, one Federal Energy Regulatory Commission training session, and one strategy session. Each incumbent director attended 100% of all meetings of the Board and committees of which he or she was a member during 2013. Our directors are expected to attend our Annual Meeting of Shareholders, and all of our incumbent directors, with the exception of Messrs. Cecil and Trujillo who were not yet members of the Board, attended the 2013 Annual Meeting of Shareholders.

The tables below identify the members and briefly summarize the responsibilities of the Board’s committees, which include the Executive Committee, the Compensation Committee, the Nominating and Governance Committee, the Audit Committee and the Nuclear Oversight Committee. The charters of the Compensation Committee, the Nominating and Governance Committee and the Audit Committee can be found on SCANA’s website at www.scana.com under the caption, “Company Profile — Corporate Governance,” and copies are also available in print upon request to the Corporate Secretary, SCANA Corporation, 220 Operation Way, Mail Code D133, Cayce, South Carolina 29033.

NAME OF COMMITTEE AND MEMBERS	PRINCIPAL FUNCTIONS OF THE COMMITTEE	2013 MEETINGS
COMPENSATION COMMITTEE M. K. Sloan, Chairman J. W. Martin, III J. M. Micali H. C. Stowe	• reviews and makes recommendations to the Board with respect to compensation plans • recommends to the Board persons to serve as our senior officers and as senior officers of our subsidiaries • recommends to the Board salary and compensation levels, including fringe benefits, for our officers and officers of our subsidiaries • approves goals and objectives with respect to the compensation of the Chief Executive Officer, evaluates the Chief Executive Officer’s performance and sets his compensation based on this evaluation • reviews succession and continuity planning with the Chief Executive Officer • reviews the investment policies of our Retirement Plan • reviews long-term strategic plans and performance in regard to management of human resources, including safety, health, labor/employee relations and equality of treatment • reviews our operating performance relative to our bonus and incentive programs • reviews management’s Compensation Discussion and Analysis relating to executive compensation prior to its inclusion in our proxy statement • approves the inclusion of a Compensation Committee Report in our proxy statement • reviews the level of SCANA stock ownership by senior executive officers to determine if each is in compliance with the Company’s minimum ownership requirement, and, as may be requested and appropriate, grants temporary waivers from such requirements • executes the duties and responsibilities, and exercises the authority, set forth in the Compensation Committee Charter • evaluates annually its own performance and the adequacy of its charter	3
NOMINATING AND GOVERNANCE COMMITTEE J. A. Bennett, Chairman J. W. Martin, III J. M. Micali L. M. Miller J. W. Roquemore M. K. Sloan H. C. Stowe	• identifies individuals whom the Committee believes are qualified to become Board members in accordance with the nominating criteria set forth below (the “Director Qualification Criteria”), and recommends that the Board select such individuals as nominees to stand for election at each annual meeting of shareholders of SCANA • reviews and evaluates all persons recommended by shareholders to be Board nominees for director in accordance with the Director Qualification Criteria • evaluates the qualifications and performance of incumbent directors and determines whether to recommend them to the Board for re-election • in the case of a Board vacancy (including a vacancy created by an increase in the size of the Board), recommends to the Board in accordance with the Director Qualification Criteria an individual to fill such vacancy either through appointment by the Board or through election by shareholders • reviews the independence of SCANA’s directors as defined by the New York Stock Exchange and as set forth in SCANA’s Governance Principles, and makes recommendations to the Board regarding director independence • monitors the orientation and education needs of directors and recommends action to the Board, individual directors and management where appropriate • reviews the level and form of director compensation and recommends changes to the Board for consideration and approval • reviews the level of SCANA stock ownership by directors to determine if each director is in compliance with the Company’s minimum ownership requirement, and, as may be requested and appropriate, grants temporary waivers from such requirements as permitted by SCANA’s Governance Principles	5

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NAME OF COMMITTEE AND MEMBERS	PRINCIPAL FUNCTIONS OF THE COMMITTEE	2013 MEETINGS
	• reviews reports and disclosures of insider and affiliated party transactions and makes recommendations to the Board regarding such transactions • evaluates periodically the desirability of, and recommends to the Board, any changes in the size, composition, organization and operational structure of the Board • annually, or to fill vacancies, identifies Board members qualified to serve on committees of the Board in accordance with the Board Committee Member Qualifications, and recommends such persons to the Board for appointment to such committees, including a recommended Chairperson for each committee • annually, or to fill vacancies, recommends to the Board the appointment of a Lead Director • reviews annually membership and responsibilities of Board committees and recommends to the Board any changes that may be appropriate • reviews annually and revises as necessary, SCANA’s Governance Principles, taking into account provisions of the Securities Exchange Act of 1934, the listing standards of the New York Stock Exchange and any other source or sources the Committee deems appropriate • initiates and oversees annually an evaluation of (i) the quality, sufficiency and timeliness of information furnished by management to the directors in connection with Board and committee meetings and other activities of the directors, (ii) the Board’s effectiveness, (iii) the composition, organization (including committee structure, membership and leadership) and practices of the Board, (iv) tenure and other policies related to the directors’ service on the Board, and (v) corporate governance matters generally; and recommends action to the Board where appropriate • provides guidance and assistance to the Board in performing the Board’s annual self evaluation • conducts an annual performance evaluation to compare the performance of the Committee to the requirements of its charter and any other duties or responsibilities delegated to the Committee by the Board and reports to the Board the results of the evaluation, which may take the form of an oral presentation by a member of the Committee to the Board • recommends to the Board any improvements to the Committee’s charter that the Committee deems to be necessary or appropriate • performs such other duties or responsibilities consistent with the Committee’s charter expressly delegated to the Committee by the Board
AUDIT COMMITTEE (Established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934) D. M. Hagood, Chairman J. M. Micali M. K. Sloan H. C. Stowe*	• periodically meets separately with management, internal auditors and the independent registered public accounting firm to discuss and evaluate the scope and results of audits and our accounting procedures and controls • reviews major issues regarding accounting principles and financial statement preparation • reviews our financial statements before submission to the Board for approval and prior to dissemination to shareholders, the public or regulatory agencies • appoints (subject to ratification by the shareholders) the independent registered public accounting firm • sets compensation of the independent registered public accounting firm • reviews our corporate compliance and risk management programs • executes the duties and responsibilities, and exercises the authority, set forth in the Audit Committee Charter • constitutes the Qualified Legal Compliance Committee • evaluates annually its own performance and the adequacy of its charter	4
NUCLEAR OVERSIGHT COMMITTEE L. M. Miller, Chairman J. A. Bennett J. W. Martin, III J. W. Roquemore	• monitors our nuclear operations • meets periodically with our management to discuss and evaluate nuclear operations, including regulatory matters, operating results, training and other related topics • periodically tours the V.C. Summer Nuclear Station and training facilities • reviews with the Institute of Nuclear Power Operations, on a periodic basis, its appraisal of our nuclear operations • periodically presents an independent report to the Board on the status of our nuclear operations • evaluates annually its own performance and the adequacy of its charter	4
EXECUTIVE COMMITTEE K. B. Marsh, Chairman L. M. Miller M. K. Sloan H. C. Stowe	• exercises the powers of the full Board of Directors when the Board is not in session, with the exception of certain powers specifically reserved to the full Board of Directors by statute, and advises the Chief Executive Officer on other matters important to the Company (due to the size of our Board of Directors, and availability of our directors to us, the Executive Committee is rarely required to meet)	0

* The Board has determined that Mr. Stowe is an “audit committee financial expert” as defined under Item 407(d)(5) of the Securities and Exchange Commission’s Regulation S-K. Mr. Stowe is independent as defined by the New York Stock Exchange Listing Standards.

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GOVERNANCE INFORMATION

Governance Principles

Our Governance Principles can be found on our website at www.scana.com (which is not intended to be an active hyperlink; the information on SCANA’s website is not part of this proxy statement or any report filed with the Securities and Exchange Commission) under the “Company Profile — Corporate Governance” caption, and are also available in print upon request to the Corporate Secretary, SCANA Corporation, 220 Operation Way, Mail Code D133, Cayce, South Carolina 29033.

Director Independence

Our Governance Principles require that a majority of our directors be independent under the New York Stock Exchange Listing Standards and under any Director Qualification Standards recommended by the Board of Directors. To be considered “independent” pursuant to the SCANA Director Qualification Standards, a director must be determined by resolution of the Board as a whole, following thorough deliberation and consideration of all relevant facts and circumstances, to have no material relationship with us except that of director and to satisfy the independence standards of the New York Stock Exchange. Under the SCANA Director Qualification Standards, a director is required to be unencumbered and unbiased and able to make business judgments in our long-term interests and those of our shareholders as a whole, to deal at arm’s length with us, and to disclose all circumstances material to the director that might be perceived as a conflict of interest. The Director Qualification Standards are set forth in our Governance Principles, which are available on our website as noted above and further described herein under “Director Qualification Criteria” on page 15.

Our Governance Principles also prohibit Audit Committee members from having any direct or indirect financial relationship with us other than the ownership of our securities and compensation as directors and committee members.

The Board has determined that all of our current directors and director nominees, except Mr. Marsh who is our current Chairman, President, Chief Executive Officer and Chief Operating Officer, are independent under the New York Stock Exchange Listing Standards and our Governance Principles. The Board has also determined that each member of the Audit Committee, Compensation Committee, and Nominating and Governance Committee is independent under the New York Stock Exchange Listing Standards and our Governance Principles.

Board Leadership Structure, Executive Sessions of Non-Management Directors and Lead Director

Our bylaws provide for a Chairman of the Board, to be chosen by the Board from among its members, who shall, if present, preside at meetings of the shareholders and Board of Directors, who may call special meetings of the shareholders and the Board of Directors, and who shall perform such other duties as may be assigned by the Board. The bylaws also permit the Chief Executive Officer, if he or she is a member of the Board, to be chosen as the Chairman. Our Governance Principles provide for the positions of Chairman and Chief Executive Officer to be held by the same person, and for more than 20 years, our Chief Executive Officer has been chosen as Chairman of the Board.

We believe this leadership structure is appropriate because it has served us well for over two decades, and because all of our current directors are independent, except Mr. Marsh, who is our Chairman, Chief Executive Officer, President and Chief Operating Officer. Many of our directors also live and work, or have substantial business interests in our service area; therefore, they have access to information about us and our operations from sources other than our management’s presentations to the Board. Further, South Carolina law and our bylaws make it clear that the business and affairs of the Company are managed under the direction of the Board of Directors, and that management control is subject to the authority of the Board of Directors to appoint and remove any of our officers at any time.

To promote open discussion among themselves, our independent directors meet regularly in executive session without members of management present. The Board annually elects a Lead Director to preside at all meetings at which the Chairman is not present, including executive sessions of the independent directors held at each regularly scheduled Board meeting. In 2013, Mr. Stowe was elected Lead Director to serve until the 2014 Annual Meeting of

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Shareholders. The Lead Director also has the authority to call meetings of the independent directors when necessary or appropriate. The Chairs of the Audit, Compensation, Nuclear Oversight, and Nominating and Governance Committees of the Board each preside as the Chair at meetings of independent directors at which the Lead Director is not present when the principal items to be considered are within the scope of authority of his or her Committee.

Board’s Role in Risk Oversight

As noted above, our business and affairs are managed under the direction of our Board of Directors. This includes the Board overseeing the types and amounts of risks undertaken. In discharging its oversight responsibilities, the Board relies on a combination of the business experience of members of the Board and the expertise and business experience of our officers and employees, as well as, from time to time, advice of various consultants and experts. An appropriate balancing of risks and potential rewards with the long-term goals of the Company is, and historically has been, implicit in the decisions and policies of the Board. Because risk oversight is so thoroughly interwoven into the direction of the Board, other than as set forth below, no special provision has been made for that oversight in the Board’s leadership structure.

The Board has established a management-level Risk Management Committee which reports directly to the Audit Committee of the Board. The Risk Management Committee is comprised of the Company’s senior executive officers, the Treasurer (who is also the Company’s Risk Management Officer) and the Chief Information Officer. The Company’s Chief Executive Officer serves as Chair of the Risk Management Committee. Committee membership is comprised of senior executive officers in order to bring together expertise in general business and all operational areas, as well as finance, legal, administrative and regulatory areas. The Risk Management Officer oversees a staff of eight employees with primary responsibility in the area of risk management.

The Risk Management Committee conducts regularly scheduled meetings at which the Committee receives presentations from management representatives. The Committee also meets on an as needed basis between regularly scheduled meetings. Pursuant to authority granted by the Board of Directors, the Committee sets policies and guidelines for risk management. The Committee has also established extensive sub-committees that work closely with management and employees to review, discuss and monitor risks. The use of sub-committees allows expertise to be tailored to the risks of a particular operation.

At each quarterly meeting of the Board, the Audit Committee receives a report from the Risk Management Officer. Several members of the Risk Management Committee are also present at the Audit Committee meetings to provide details of the Committee’s work and respond to questions raised by Audit Committee Members. Also at each quarterly meeting of the Board of Directors, the Audit Committee Chair reports to the full Board any activities or reports of the Risk Management Committee that require the Board’s attention.

Director Nominations Process

The Nominating and Governance Committee recommended to the Board the individuals nominated for director positions at the 2014 Annual Meeting.

The Nominating and Governance Committee will consider for recommendation to the Board as Board of Directors’ nominees, candidates recommended by shareholders if the shareholders comply with the following requirements. If a shareholder wishes to recommend a candidate to the Nominating and Governance Committee for consideration as a Board of Directors’ nominee, such shareholder must submit in writing to the Nominating and Governance Committee the recommended candidate’s name, a brief resume setting forth the recommended candidate’s business and educational background and qualifications for service, and a notarized consent signed by the recommended candidate stating the recommended candidate’s willingness to be nominated and to serve. This information must be delivered to the SCANA Nominating and Governance Committee, c/o the Corporate Secretary at the Company’s address and must be received no later than 120 days prior to the first anniversary of the date of the proxy statement sent to shareholders in connection with the preceding year’s annual meeting for a potential candidate to be considered as a potential Board of Directors’ nominee. The Nominating and Governance Committee may request further information if it determines a potential candidate may be an appropriate nominee. Director candidates recommended by shareholders that comply with these requirements will be considered on the same basis as candidates otherwise chosen by the Nominating and Governance Committee.

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Director candidates recommended by shareholders will not be considered for recommendation by the Nominating and Governance Committee as potential Board of Directors’ nominees if the shareholder recommendations are received later than 120 days prior to the first anniversary of the date of the proxy statement sent to shareholders in connection with the preceding year’s annual meeting. If the Nominating and Governance Committee chooses not to recommend a shareholder candidate as a Board of Directors’ nominee, or if a shareholder chooses to personally nominate a candidate, the shareholder may come to an annual meeting and nominate a director candidate for election at the annual meeting if the shareholder has given notice of his intention to do so in writing to the SCANA Corporate Secretary at least 120 days prior to the first anniversary of the date of the proxy statement sent to shareholders in connection with the preceding year’s annual meeting. Such shareholder nominations must also comply with the other requirements in our bylaws. Any shareholder may request a copy of the relevant bylaw provision by writing to the Office of the Corporate Secretary, SCANA Corporation, 220 Operation Way, Mail Code D133, Cayce, South Carolina 29033. Nominations not made in accordance with these requirements may be disregarded by the presiding officer of the meeting, and upon his or her instructions, the voting inspectors shall disregard all votes cast for each such nominee.

Independent Director Recruiting Firm

In October 2012, the Nominating and Governance Committee directed management to retain an independent executive recruiting firm to assist the Committee in identifying and evaluating potential director candidates who meet the director qualification criteria discussed below. As a result, our newest directors, Messrs. Cecil and Trujillo, were elected to the Board in October 2013. It is the intention of the Nominating and Governance Committee to pursue additional potential directors during 2014.

Director Qualification Criteria

In identifying and evaluating potential nominees, the Nominating and Governance Committee Charter directs the Committee to take into account applicable requirements for directors under the Securities Exchange Act of 1934, the Listing Standards of the New York Stock Exchange and the Director Qualification Standards in our Governance Principles, including our policy that a majority of our directors be independent.

The Nominating and Governance Committee may take into consideration such other factors and criteria as it deems appropriate in evaluating a candidate, including his or her knowledge, expertise, skills, integrity, judgment, business or other experience and reputation in the business community, the interplay of the candidate’s experience with the experience of other Board members, diversity, and the extent to which the candidate would be a desirable addition to the Board and any committees. Although the Nominating and Governance Committee does not have a specific policy with regard to the consideration of diversity in identifying director nominees, the Committee considers racial and gender diversity, as well as diversity in business experience among all of the directors, as part of the total mix of information it takes into account in identifying nominees. Additionally, the Director Qualification Standards set forth in our Governance Principles include the following:

• Directors must possess and have demonstrated the highest personal and professional ethics, integrity and values consistent with ours;

• Directors must be unencumbered and unbiased and able to make business judgments in our long-term interests and those of our shareholders as a whole;

• Directors must deal at arm’s length with us and our subsidiaries and disclose all circumstances material to the director that might be perceived as a conflict of interest;

• Directors must be committed to the enhancement of the long-term interests of our shareholders;

• Directors must be willing to challenge the strategic direction of management, exercising mature judgment and business acumen;

• Directors must be willing to devote sufficient time and care to the exercise of their duties and responsibilities;

• Directors must possess significant experience in management positions of successful business organizations;

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• Directors who serve as chief executive officers or equivalent positions should not serve on more than two boards of public companies in addition to our Board; other directors should not serve on more than four boards of public companies in addition to our Board; and

• The term of office of a director who is not a salaried employee of SCANA will expire at the annual meeting next preceding the date on which such director attains age 70.

Our bylaws require that our independent directors hold SCANA common stock equal to the number of shares granted in the five most recent annual retainers, as such retainer may be adjusted from time to time.

Director Share Ownership Requirements

As noted in the Director Qualifications set forth in the preceding section, our bylaws require that our independent directors hold SCANA common stock equal to the number of shares granted in the five most recent annual retainers. Currently, a portion of the retainer fees paid to independent directors is required to be paid in shares of our common stock, which is issued under our Director Compensation and Deferral Plan. For 2013, the number of shares issued to each independent director to satisfy the annual stock retainer was 2,113 shares with the exception of Messrs. Cecil and Trujillo who each received 566 shares. As of February 2014, all independent directors whose terms will continue after the 2014 Annual Meeting, or who have been nominated for reelection, met this stock ownership requirement, with the exception of Messrs. Cecil and Trujillo who have until October 10, 2019 to acquire the required level of stock ownership and who are both currently on track to meet the requirement. All subsequently elected independent directors will have six years from the date of their election to the Board to meet the requirement. The Nominating and Governance Committee conducts an annual review of the level of share ownership for each independent director to ensure compliance with the requirement. The Nominating and Governance Committee also has the discretion to grant a temporary waiver of the minimum share ownership requirement if an independent director demonstrates to the Nominating and Governance Committee that such a waiver is appropriate due to a financial hardship or for other good reason.

Under the Director Compensation and Deferral Plan, independent directors may make an annual irrevocable election to defer all or a portion of the annual stock retainer fee into a hypothetical investment in our common stock, with distribution from the Plan to be ultimately payable in shares of our common stock. Independent directors may also elect for other fees to be deferred into a hypothetical investment in our common stock under the Plan, with distribution from the Plan to be ultimately payable in shares of common stock. Shares held directly and amounts deferred pursuant to the Director Compensation and Deferral Plan and denominated in shares are taken into consideration in determining if our independent directors meet the minimum share ownership requirement under our bylaws. See “Director Compensation — Director Compensation and Deferral Plan” on page 53.

Majority Voting for the Election of Directors

In February 2012, our Board amended our Governance Principles to implement a majority voting standard for the election of our directors, pursuant to which each director nominee agrees that, as a condition to being nominated, if, in an uncontested election of directors, such nominee receives a greater number of votes “withheld” from his or her election than votes “for” his or her election, then such nominee will, within five days following the certification of the shareholder vote, tender his or her written resignation to the Chairman of the Board for consideration by the Nominating and Governance Committee. The Nominating and Governance Committee will consider such tendered resignation, and promptly following the date of the shareholders’ meeting at which the election occurred, will make a recommendation to the Board concerning the acceptance or rejection of such resignation. In determining its recommendation to the Board, the Nominating and Governance Committee will consider all factors deemed relevant by the members of the Committee including, without limitation, the stated reason or reasons why shareholders who cast “withhold” votes for the director did so, the qualifications of the director (including, for example, the impact the director’s resignation would have on the Company’s compliance with the requirements of the Securities and Exchange Commission, the New York Stock Exchange and our Corporate Governance Principles), and whether the director’s resignation from the Board would be in the best interests of the Company and its shareholders.

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The Nominating and Governance Committee also will consider a range of possible alternatives concerning the director’s tendered resignation as members of the Committee deem appropriate, including, without limitation, acceptance of the resignation, rejection of the resignation, or rejection of the resignation coupled with a commitment to seek to address and cure the underlying reasons reasonably believed by the Nominating and Governance Committee to have substantially resulted in the “withheld” votes. The Board will take formal action on the Nominating and Governance Committee’s recommendation no later than 90 days following the date of the shareholders’ meeting at which the election occurred. Following the Board’s decision on the Nominating and Governance Committee’s recommendation, the Company will promptly disclose, in a Form 8-K filed with the Securities and Exchange Commission, the Board’s decision, together with a full explanation of the process by which the decision was made and, if applicable, the Board’s reason or reasons for rejecting the tendered resignation.

Communications with the Board of Directors, Including Non-Management Directors

Shareholders and other interested parties can communicate with the Board, with the independent directors as a group or with any director by writing to them, c/o Gina Champion, Corporate Secretary, SCANA Corporation, 220 Operation Way, Mail Code D133, Cayce, South Carolina 29033, or by sending an e-mail to independentdirectors@scana.com (for correspondence to the independent directors), to chairman@scana.com (for correspondence to the CEO/chairman) or to gchampion@scana.com (for correspondence to a particular director). Interested parties also may communicate with the chair of the following Committees by sending an e-mail to: auditchair@scana.com, humanresourceschair@scana.com, or nomandgovchair@scana.com. The Corporate Secretary may initially review communications to directors and send a summary to the directors, but has discretion to exclude from transmittal any communications that are commercial advertisements or other forms of solicitation or individual service or billing complaints (although all communications are available to the directors at their request). The Corporate Secretary will forward to the directors any communications raising substantive issues.

Prohibition on Margining or Pledging of Shares

Our Insider Trading Policy prohibits officers, directors, employees and related persons from pledging or margining shares of the Company’s common stock.

SCANA’s Code of Conduct & Ethics

All of our employees (including the Chief Executive Officer, Chief Financial Officer, President and Controller) and directors are required to abide by the SCANA Code of Conduct & Ethics (the “Code of Conduct”) to ensure that our business is conducted in a consistently legal and ethical manner. The Code of Conduct forms the foundation of a comprehensive process that promotes compliance with corporate policies and procedures, an open relationship among colleagues that contributes to good business conduct, and a belief in the integrity of our employees. Our policies and procedures cover all areas of business conduct and require adherence to all laws and regulations applicable to the conduct of our business.

The full text of the Code of Conduct is published on our website, at www.scana.com (which is not intended to be an active hyperlink; the information on SCANA’s website is not part of this proxy statement or any report filed with the Securities and Exchange Commission) under the “Company Profile — Code of Conduct” caption, and a copy is also available in print upon request to the Corporate Secretary, SCANA Corporation, 220 Operation Way, Mail Code D133, Cayce, South Carolina 29033. We intend to disclose future amendments to, or waivers from, certain provisions of the Code of Conduct on our website within two business days following the date of such amendment or waiver.

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RELATED PARTY TRANSACTIONS

Our Governance Principles and Nominating and Governance Committee Charter address independence requirements for our directors. As part of our independence analysis, our Nominating and Governance Committee must review and assess any related party transactions involving our directors and their immediate family members and certain of their affiliates as required by the New York Stock Exchange Listing Standards. Our Governance Principles also address director requirements for avoidance of conflicts of interest and disclosure of conflicts of interest or potential conflicts of interest, and prohibit loans or extensions of credit to directors. Our Code of Conduct addresses requirements for avoidance of conflicts of interest by all of our employees. Our Governance Principles, Nominating and Governance Committee Charter and Code of Conduct are all written documents. With the exception of annual director and officer questionnaires, our Governance Principles, our Code of Conduct, and our Nominating and Governance Committee Charter, there are no additional written policies and procedures relating to the review, approval or ratification of related party transactions by the Board.

To help us perform our independence and related party transaction analysis, we require that each senior executive officer, executive officer, director and director nominee complete an annual questionnaire and report all transactions with us in which such persons (or their immediate family members and certain of their affiliates) had or will have a direct or indirect material interest (except for salaries and other compensation and benefits, directors’ fees, and dividends on our stock). It is our general intention to avoid such transactions. Our General Counsel reviews responses to the questionnaires and any other information about related party transactions that may be brought to his attention. We use the questionnaires and the annual Code of Conduct training to help ensure the effective implementation and monitoring of compliance with such policies and procedures. If any such related party transactions are disclosed, they are reviewed by the Nominating and Governance Committee pursuant to the requirements of its Charter. If appropriate, any such transactions are submitted to the Board for approval.

The Nominating and Governance Committee does not use any formal written standards in determining whether to submit a related party transaction to the Board for approval. As noted above, we attempt to avoid such transactions altogether. On the rare occasions when such transactions have arisen, our Nominating and Governance Committee, which is comprised of a majority of our independent Board members, reviewed the proposed or actual transactions and utilized their business judgment to determine which of them should be submitted for review to the full Board. In practice, all such transactions that have arisen in recent years have been reviewed by the full Board, even when they were well below the threshold for proxy statement disclosure and below the threshold at which director independence could be compromised.

The types of transactions that have been reviewed in the past include the purchase and sale of goods, services or property from companies for which our directors serve as executive officers or directors, the purchase of financial services and access to lines of credit from banks for which our directors serve as executive officers or directors, and senior officer relocation benefits. During the year ended December 31, 2013, there was only one transaction reported to the Board as set forth below.

In connection with the promotion of D. Russell Harris to President of Gas Operations for South Carolina Electric and Gas Company, Mr. Harris was required to move from Gastonia, North Carolina to Columbia, South Carolina, and therefore was eligible for certain relocation benefits under our employee relocation programs. Those benefits included our purchasing Mr. Harris’ previous residence for $514,500, as well as reimbursing certain of his relocation expenses and providing an expense allowance and tax gross-up payments, which totaled approximately $116,000 in 2013. The purchase price for Mr. Harris’ residence was the agreed-upon value between the Company and Mr. Harris, after considering his purchase price and a third party appraisal. In addition, we agreed to indemnify our relocation agent for various matters potentially associated with the purchase and resale of the residence, and Mr. Harris agreed to indemnify us against certain of those indemnification obligations. We intend to resell the residence as soon as it is prudent to do so.

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SHARE OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

SECURITY OWNERSHIP OF MANAGEMENT

The following table lists the amounts of our common stock beneficially owned on February 28, 2014, by each director, each nominee, each person named in the Summary Compensation Table on page 38, and all directors and executive officers as a group.

Name of Beneficial Owner		Amount and Nature of Beneficial Ownership(1)(2)(3)(4)		Percent of Class
K. B.	Marsh		42,953		*
J. E.	Addison		20,749		*
S. A.	Byrne		22,418		*
G. J.	Bullwinkel, Jr.		35,744		*
R. T.	Lindsay		2,093		*
J. A.	Bennett		39,488		*
J. F.A.V.	Cecil		1,124		*
D. M.	Hagood		18,460		*
J. W.	Martin, III		8,717		*
J. M.	Micali		23,631		*
L. M.	Miller		55,624		*
J. W.	Roquemore		30,107		*
M. K.	Sloan		52,380		*
H. C.	Stowe		36,952		*
A.	Trujillo		1,124		*
All executive officers and directors as group (22 persons)			570,466		*

*Less than 1%

(1) Includes shares purchased through February 28, 2014 by the Trustee under the SCANA Corporation Stock Purchase-Savings Plan.

(2) Includes hypothetical shares acquired under the Director Compensation and Deferral Plan. These hypothetical shares are paid out in shares and do not have voting rights. As of February 28, 2014, the following directors had acquired the following numbers of hypothetical shares: Messrs. Bennett — 36,124; Hagood — 17,197; Martin — 8,096; Micali — 22,631; Roquemore — 16,007; Sloan — 49,731; Stowe — 33,513; and Ms. Miller — 51,213.

(3) Hypothetical shares acquired under the Executive Deferred Compensation Plan are not included in the above table. These hypothetical shares are paid out in cash and do not have voting rights. As of February 28, 2014, the following officers had acquired the following numbers of hypothetical shares: Messrs. Marsh — 17,827; Addison — 744; Byrne — 22,845; and Bullwinkel — 5,856.

(4) Includes shares owned by close relatives and/or shares held in trust for others, as follows: other executive officers as a group – 10,816.

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FIVE PERCENT BENEFICIAL OWNERSHIP OF SCANA COMMON STOCK

The following table provides information about persons known by us to be the beneficial owners of more than five percent of our common stock as of December 31, 2013. This information was obtained from Schedules 13G filed with the Securities and Exchange Commission and we have not independently verified it.

Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership			Percent of Class
SCANA Corporation Stock Purchase - Savings Plan     Bank of America, N.A., as Trustee         1300 Merrill Lynch Drive         Third Floor         Pennington, NJ 08534		13,748,811	(1)		9.8
BlackRock, Inc.         40 East 52nd Street         New York, NY 10022		10,887,893	(2)		7.7
The Vanguard Group, Inc.         100 Vanguard Boulevard         Malvern, PA 19355		9,133,806	(3)		6.49

(1) The SCANA Corporation Stock Purchase - Savings Plan has shared power to vote and dispose of these shares. Participants have the opportunity to give voting instructions to the plan trustee with respect to shares held in their accounts, and the trustee is required to vote the shares in accordance with such instructions. Shares that are not voted by participants are voted proportionally to the Plan shares voted.

(2) In its most recently filed Schedule 13G BlackRock, Inc. reported sole voting power with respect to 9,616,823 shares, and sole dispositive power with respect to all 10,887,893 shares.

(3) In its most recently filed Schedule 13G The Vanguard Group, Inc. reported sole voting power with respect to 287,135 shares, sole dispositive power with respect to 8,924,371 shares, and shared dispositive power with respect to 209,435 shares.

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EXECUTIVE COMPENSATION

Compensation Committee Processes and Procedures

Our Compensation Committee, which is comprised entirely of independent directors, administers our senior executive compensation program. Compensation decisions for all senior executive officers are approved by the Compensation Committee and recommended by the Committee to the full Board for final approval. The Committee considers recommendations from our Chairman and Chief Executive Officer in setting compensation for senior executive officers.

In addition to attendance by members of the Compensation Committee, the Committee’s meetings are also regularly attended by our Chairman and Chief Executive Officer, our Senior Vice President of Administration and Human Resources Department employees. At each meeting the Committee also meets in executive session without members of management present. The Chairman of the Committee reports the Committee’s recommendations on executive compensation to the Board of Directors. Our Human Resources, Tax and Finance Departments support the Compensation Committee in its duties, and the Committee may delegate authority to these departments to fulfill administrative duties relating to our compensation programs.

The Committee has the authority under its charter to retain, approve fees for, and terminate advisors, consultants and others as it deems appropriate to assist in the fulfillment of its responsibilities. Prior to 2012, the Committee had, however, historically not retained its own compensation consultant, but rather had used relevant information provided to us by management’s consultant, Towers Watson. The Committee used this information to assist it in carrying out its responsibilities for overseeing matters relating to compensation plans and compensation of our senior executive officers. Using information provided by a national compensation consultant helps assure the Committee that our policies for compensation and benefits are competitive and aligned with utility and general industry practices.

In 2012, the Committee engaged the services of its own independent compensation consultant, Pearl Meyer & Partners, to perform an evaluation of compensation data previously provided by management’s compensation consultant, and the Committee continues to engage Pearl Meyer & Partners as its independent compensation consultant. The Committee believes that engaging its own independent compensation consultant eliminates the appearance of any potential conflict of interest that might arise because management’s consultant also performs other services for the Company. Pearl Meyer & Partners does not perform additional services for the Company.

The Compensation Committee has assessed the independence of Pearl Meyer & Partners pursuant to Securities and Exchange Commission rules and New York Stock Exchange Listing Standards and determined that Pearl Meyer & Partners’ work for the Compensation Committee does not raise any conflict of interest. Towers Watson continues to serve as management’s executive officer and director compensation consultant.

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Compensation Committee Interlocks and Insider Participation

During 2013, decisions on various elements of executive compensation were made by the Compensation Committee. No officer, employee, former officer or any related person of SCANA or any of its subsidiaries served as a member of the Compensation Committee.

The directors who served on the Compensation Committee during 2013 were:

Mr. Maceo K. Sloan, Chairman

Mrs. Sharon A. Decker (served until April 25, 2013)

Mr. Joshua W. Martin, III

Mr. James M. Micali

Mr. Harold  C. Stowe

Compensation Risk Assessment

Our Human Resources, Risk Management, and Legal Departments have jointly reviewed our compensation policies and procedures to determine whether they present a significant risk to the Company. Based on this review we have concluded that our compensation policies and procedures for all employees are not reasonably likely to have a material adverse effect on the Company. Our annual incentive compensation plans for all employees are structured such that appropriate limits are in place to discourage excessive risk taking. In addition, all leadership level employees who are in a position to effect significant policies or projects have compensation at risk on both a short- and long-term basis, which we believe discourages excessive risk taking and encourages supervision of any risk related activities by other employees. Our compensation programs and policies, including our senior executive officer share ownership requirements, reward consistent, long-term performance by heavily weighting leadership level compensation to long-term incentives that reward stock, financial, and operating performance. In addition, all of our senior executive officers, who are also members of our Risk Management Committee, oversee and approve individual and business unit objectives for their areas of responsibility so they are positioned to report any risk associated with such individual or business unit objectives to the Risk Management Committee.

Compensation Discussion and Analysis

Objectives and Philosophy of Executive Compensation

Our senior executive compensation program is designed to support our overall objective of increasing shareholder value by:

• Hiring and retaining premier executive talent;

• Having a pay-for-performance philosophy that links total rewards to achievement of corporate, business unit and individual goals, and places a substantial portion of pay for senior executives at risk;

• Aligning the interests of executives with the long-term interests of shareholders through long-term equity-based incentive compensation; and

• Ensuring that the elements of the compensation program focus on and appropriately balance our financial, customer service, operational and strategic goals, all of which are crucial to achieving long-term results for our shareholders.

We have designed our compensation program to reward senior executive officers for their individual and collective performance and for our collective performance in achieving goals for growth in basic earnings per share and total shareholder return and other annual and long-term business objectives. We believe our program performs a vital role in keeping executives focused on improving our performance and enhancing shareholder value while rewarding successful individual executive performance in a way that helps to assure retention.

The following discussion provides an overview of our compensation program for all of our senior executive officers (for 2013, a group of 12 people who are at the level of senior vice president and above), as well as a specific discussion of compensation for our Chief Executive Officer, our Chief Financial Officer and the other executive officers named in the Summary Compensation Table that follows this “Compensation Discussion and Analysis.” In this discussion, we refer to the executives named in the Summary Compensation Table as “Named Executive Officers.”

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Principal Components of Executive Compensation

During 2013, senior executive compensation consisted primarily of three key components: base salary, short-term cash incentive compensation, and long-term equity-based incentive compensation (under the shareholder-approved Long-Term Equity Compensation Plan). We also provide various additional benefits to senior executive officers, including health, life and disability insurance plans, retirement plans, change in control arrangements, limited perquisites, and, if appropriate, severance and termination benefits. The Compensation Committee makes its decisions about how to allocate senior executive officer compensation among base salary, short-term cash incentive compensation and long-term equity-based incentive compensation on the basis of market information and analysis provided by management’s compensation consultant, and our goals of remaining competitive with the compensation practices of a group of surveyed companies and of linking compensation to our corporate performance and individual senior executive officer performance. We also evaluate the market information for specific positions to ensure we account for internal equity considerations. At the Committee’s discretion, information used or provided by management, or provided by management’s compensation consultant to assist the Committee in making its decisions, may be reviewed by the Committee’s independent compensation consultant, Pearl Meyer & Partners.

A more detailed discussion of each of these components of senior executive officer compensation, the reasons for awarding such types of compensation, the considerations in setting the amounts of each component of compensation, the amounts actually awarded for the periods indicated, and various other related matters are set forth in the sections below.

Factors Considered in Setting Senior Executive Officer Compensation

Use of Market Surveys and Peer Group Data

We believe it is important to consider comparative market information about compensation paid to executive officers of other companies in order to remain competitive in the executive workforce marketplace. We want to attract and retain highly skilled and talented senior executive officers who have the ability to carry out our short- and long-term goals. To do so, we must be able to compensate them at levels that are competitive with compensation offered by other companies in our business or geographic marketplace that seek similarly skilled and talented executives. Accordingly, we consider market survey results in establishing all components of compensation. The market survey information is provided to us approximately every other year by management’s compensation consultant. In years in which management’s consultant does not provide us with market survey information, and when we require updated information, our process may be to apply an aging factor to the prior year’s information with assistance from management’s consultant, based on its experience in the marketplace. Compensation decisions for 2013 were based on a compensation survey performed in 2011 by management’s compensation consultant, Towers Watson. Prior to the consultant’s conducting the market survey, we assist management’s consultant in matching our positions with benchmark positions in its database by comparing the specific responsibilities of our positions with the benchmark duties. If management’s consultant is unable to find an exact match for one of our positions in the consultant’s database due to variances in duties and/or position level, we may assist management’s consultant in identifying the most similar position. The market survey information may then be adjusted upward or downward as necessary to match the position as closely as possible.

Our goal is to set base salary and short- and long-term incentive compensation for our senior executive officers at the median (50th percentile) of compensation paid for similar positions by the companies included in the market surveys. We generally set our target at the median because we believe this target will meet the requirements of most of the persons we seek to hire and retain in our geographic area, and because we believe it is fair both to us and to the executives. Variations to this objective may, however, occur as dictated by the experience level of the individual, internal equity, need for specialized talent, and market factors. We do not set a target level for broad-based benefits for our senior executive officers, but we believe our broad-based benefits are approximately at the median.

The companies included in the market survey are a group of utilities and general industry companies of various sizes in terms of revenue. Approximately half of the companies included in the 2011 market survey had substantially the same levels of annual revenues as we had, while the remainder had revenues ranging from one-third to not greater than 3.8 times our revenues. Market survey results for positions may be size-adjusted using regression analysis to account for these differences in company revenues, which in turn are viewed as a proxy for measuring the relative scope and complexity of the business operations.

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The companies included in the 2011 market survey we used in connection with setting base salaries and short- and long-term incentive compensation for 2013, and the states in which they are headquartered are listed below:

Utility Industry: AGL Resources, Inc. (GA); Alliant Energy Corporation (WI); Ameren Corporation (MO); Avista Corp. (WA); CenterPoint Energy, Inc. (TX); CMS Energy Corporation (MI); Dominion Resources, Inc. (VA); DPL, Inc. (OH); Duke Energy Corporation (NC); Edison International (CA); Entergy Corporation (LA); FirstEnergy Corporation (OH); Hawaiian Electric Industries, Inc. (HI); NextEra Energy, Inc. (FL); Northeast Utilities (CT); NV Energy, Inc. (NV); OGE Energy Corporation (OK); Pepco Holdings, Inc. (DC); Pinnacle West Capital Corporation (AZ); PNM Resources, Inc. (NM); Portland General Electric Co. (OR); PPL Corporation (PA); Progress Energy, Inc. (NC); Public Service Enterprise Group, Inc. (NJ); Sempra Energy (CA); Southern Company (GA); TECO Energy, Inc. (FL); Westar Energy, Inc. (KS); Wisconsin Energy Corporation (WI); Xcel Energy, Inc (MN).

General Industry: Armstrong World Industries, Inc. (PA); Avery Dennison Corporation (CA); Ball Corporation (CO); Cameron International Corporation (TX); Eastman Chemical Company (TN); Ecolab Inc. (MN); Goodrich Corporation (NC); Hanesbrands, Inc. (NC); The Hershey Company (PA); Level 3 Communications, Inc. (CO); ManTech International Corporation (VA); Mattel, Inc. (CA); MeadWestvaco Corporation (VA); Pitney Bowes, Inc. (CT); Rockwell Automation, Inc. (WI); Rockwell Collins, Inc. (IA); Sealed Air Corporation (NJ); Snap-on, Inc. (WI); Sonoco Products Company (SC); Steelcase Inc. (MI); Terex Corporation (CT); The Scotts Miracle-Gro Company (OH); The Sherwin-Williams Company (OH); Unisys Corporation (PA); USG Corporation (IL).

We believe the utilities included in our market survey are an appropriate group to use for compensation comparisons because they align well with our revenues, the nature of our business and workforce, and the talent and skills required for safe and successful operations. We believe the additional non-utility companies included in our market survey are appropriate to include in our comparisons because they align well with our revenues, and are the types of companies that might be expected to seek executives with the same general skills and talents as the executives we are trying to attract and retain in our geographic area. The companies we use for comparisons may change from time to time based on the factors discussed above.

To make comparisons with the market survey results, we generally divide all of our senior executive officers into utility and non-utility executive groups — that is, executive officers whose responsibilities are primarily related to utility businesses and require a high degree of technical or industry-specific knowledge (such as electrical engineering, nuclear engineering or gas pipeline transmission), and those whose responsibilities are more general and do not require such specialized knowledge (such as business, finance, and other corporate support functions). We then attempt to match to the greatest degree possible our positions with similar positions in the survey results. We may blend the survey results to achieve what we believe is an appropriate comparison.

We also use performance data covering a larger peer group of utilities in determining long-term equity incentive compensation under our shareholder-approved Long-Term Equity Compensation Plan, as discussed under “Long-Term Equity Compensation Plan.”

Personal Qualifications

In addition to considering market survey comparisons, we consider each senior executive officer’s knowledge, skills, scope of authority and responsibilities, job performance and tenure with us as a senior executive officer.

Mr. Marsh has been our Chairman and Chief Executive Officer since December 2011, and he has also served as our President and Chief Operating Officer since January 2011. Prior to January 2011, he served as our Senior Vice President from 1998 to January 2011, and as our Chief Financial Officer from 1996 to April 2006. He previously served as President of South Carolina Electric & Gas Company (“SCE&G”), our largest subsidiary from April 2006 to November 2011, and as SCE&G’s Chief Operating Officer from April 2006 to January 2011. Mr. Marsh previously practiced as a certified public accountant and has been with us for over 30 years. As our Chief Executive Officer, Mr. Marsh has responsibility for strategic planning, development of our senior executive officers and oversight of our operations.

Mr. Addison was appointed Executive Vice President of SCANA in January 2012, and he has served as our Chief Financial Officer since April 2006. Prior to January 2012, Mr. Addison had served as a Senior Vice President since 2006 and Vice President of Finance from 2001 to 2006. As Chief Financial Officer, he is responsible for all of our

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financial operations, including accounting, risk management, treasury, regulatory affairs, investor relations, shareholder services, taxation and financial planning, as well as our information technology functions. Mr. Addison is a certified public accountant and has been with us for 23 years.

Mr. Byrne is an Executive Vice President of SCANA, as well as President of Generation and Transmission and Chief Operating Officer of SCE&G. He is also responsible for our fossil/hydro operations. In these positions, he is responsible for overseeing all of our activities related to fossil/hydro and nuclear power, including nuclear plant operations, emergency planning, licensing, and nuclear support services, as well as overseeing construction of our new nuclear facilities. He has over 29 years of experience in the nuclear industry, and he has also held a Nuclear Regulatory Commission Senior Reactor Operator’s license. Mr. Byrne has been with us for 18 years.

Mr. Bullwinkel is a Senior Vice President of SCANA, as well as President and Chief Operating Officer of our subsidiary, SCANA Energy Marketing, Inc., and President of our subsidiaries, SCANA Communications, Inc. and ServiceCare, Inc. For a portion of 2013, he was also responsible for senior executive oversight of our subsidiary, Public Service Company of North Carolina, Incorporated, d/b/a PSNC Energy. In these positions, he is responsible for overall operations of each of these subsidiaries. Mr. Bullwinkel has been with us for 43 years.

Mr. Lindsay is a Senior Vice President and the General Counsel of SCANA and its subsidiaries. He is responsible for oversight of all legal, legal regulatory, environmental, and corporate secretary functions. Mr. Lindsay has been with us for 5 years and has more than 35 years experience as an attorney, which includes more than 20 years serving in a General Counsel role.

Other Factors Considered

In addition to the foregoing information, we consider the fairness of the compensation paid to each senior executive officer in relation to what we pay our other senior executive officers. Our Compensation Committee also considers recommendations from our Chairman and Chief Executive Officer in setting compensation for senior executive officers.

We review our compensation program and levels of compensation paid to all of our senior executive officers, including the Named Executive Officers, annually and may make adjustments based on the foregoing factors as well as other subjective factors.

In 2013, our Compensation Committee reviewed summaries of compensation components (“tally sheets”) for all of our senior executive officers, including the Named Executive Officers. These tally sheets reflect changes in compensation during the prior year, if any, and affix dollar amounts to each component of compensation. Although the Committee did not make any adjustments to executive compensation in 2013 based solely on its review of the tally sheets, it intends to continue to use such tally sheets in the future to review each component of the total compensation package, including base salaries, short- and long-term incentives, severance plans, insurance, retirement and other benefits, as a factor in determining the total compensation package for each senior executive officer.

Timing of Senior Executive Officer Compensation Decisions

Annual salary reviews are routinely conducted and any adjustments are made, and short- and long-term incentive compensation awards are routinely granted in February of each year at the first regularly scheduled Compensation Committee and Board meetings. Determinations also are made at those meetings as to whether to pay out awards under the most recently completed cycle of short- and long-term incentive compensation (which include equity based incentive compensation). Compensation determinations also may be made by the Committee at its other quarterly meetings in the case of newly hired executives, promotions of employees, or adjustments of existing employees’ compensation that could not be deferred until the February meeting. We routinely release our annual and quarterly earnings information to the public in conjunction with the quarterly meetings of our Board.

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Base Salaries

Senior executive officer base salaries are divided into grade levels based on market data for similar positions, experience and certain internal equity considerations. The Compensation Committee believes it is appropriate to set base salaries at a reasonable level that will provide executives with a predictable income base. Accordingly, base salaries are targeted at the median (50^th percentile) of the market survey data. The Compensation Committee reviews base salaries annually and makes adjustments, if appropriate, on the basis of an assessment of individual performance, relative levels of accountability, prior experience, breadth and depth of knowledge, specialized talent required for new operational initiatives, changes in market compensation practices as reflected in market survey data, and relative compensation levels within our Company. In February 2013, certain of the Named Executive Officers received base salary increases in the following percentages: Mr. Marsh, 6.3%; Mr. Addison, 5%; Mr. Byrne, 5%; and Mr. Lindsay, 6%. Such increases were based on individual performance and the degree to which the Named Executive Officers’ base salaries were below the market rate for their positions and certain internal equity considerations.

Short-Term and Long-Term Incentive Compensation

Our senior executive officer compensation program provides for both short-term incentive compensation in the form of annual cash incentive compensation, and long-term equity-based incentive compensation payable at the end of periods which have historically lasted three years. Both our Short-Term Annual Incentive and Long-Term Equity Compensation Plans promote our pay-for-performance philosophy, as well as our goal of having a meaningful amount of pay at-risk, and we believe both Plans provide us a competitive advantage in recruiting and retaining top quality talent.

We believe the Short-Term Annual Incentive Compensation Plan provides our senior executive officers with an annual stimulus to achieve short-term individual and business unit or departmental goals and short-term corporate earnings goals that ultimately help us achieve our long-term corporate goals. We believe the long-term equity-based incentive compensation counterbalances the emphasis of short-term incentive compensation on short-term results by focusing our senior executive officers on achievement of our long-term corporate goals, providing additional incentives for them to remain our employees by ensuring that they have a continuing stake in the long-term success of the Company, and significantly aligning the interests of senior executive officers with those of our shareholders.

Short-Term Annual Incentive Plan

Our Short-Term Annual Incentive Plan provides financial incentives for performance in the form of opportunities for annual incentive cash payments. Participants in the Short-Term Annual Incentive Plan include not only our senior executive officers, but also approximately 240 additional employees, including other officers, senior management, division heads and other professionals whose positions or levels of responsibility make their participation in the plan appropriate. Our Chief Executive Officer recommends, and the Compensation Committee approves, the performance measures, operational goals and other terms and conditions of incentive awards for senior executive officers, including the Named Executive Officers.

The Compensation Committee reviews and approves target short-term incentive levels at its first regularly scheduled meeting each year based on percentages assigned to each executive salary grade. Actual short-term incentive awards are based both on the Company’s achieving pre-determined financial and business objectives in the coming year, and on each senior executive officer’s level of performance in achieving his or her individual financial and strategic objectives. The Committee selected these performance metrics because it believes they are key measures of financial and operational success, and that achieving our earnings and strategic goals supports the interests of our shareholders. In assessing accomplishment of objectives, the Committee considers the difficulty of achieving each objective, unforeseen obstacles or favorable circumstances that might have altered the level of difficulty in achieving the objective, overall importance of the objective to our long-term and short-term goals, and importance of achieving the objective to enhancing shareholder value. Changes in annual target short-term incentive levels can be made if there are changes in the senior executive officer’s salary grade level that warrant a target change.

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In the discretion of the Compensation Committee, the Plan allows for an increase or decrease in short-term incentive award payouts, but cumulative adjustments to target award payouts for all participants may not increase or decrease overall award levels by more than 50%. Individual awards may nonetheless be decreased or eliminated if the Committee determines that actual results warrant a lower payout.

For a number of years prior to 2013, half of the annual cash incentive payments under the Short-Term Annual Incentive Plan were earned based on the extent to which we met designated earnings per share targets, and the other half of the payments were earned based on our Named Executive Officers and the other participants in the plan achieving their individual and business unit performance objectives. Based on the factors discussed below, the Committee changed the bases for allocation of these cash incentive payments for 2013 to place more emphasis on participants’ individual and business unit performance objectives and less emphasis on earnings per share goals.

During 2012, management redesigned its strategic planning process and, based on comments from the Compensation Committee, incorporated a process to make individual and business unit objectives and incentive goals more specific, measurable, and more closely aligned with our strategic plan. As a result of the new strategic planning process and the development of new incentive goals, management made a recommendation to the Compensation Committee to base a greater percentage of short-term incentive awards on individual and business unit performance criteria, over which the participants have significant control, rather than on earnings per share metrics, over which participants may have less control. Management discussed with the Committee that requiring participants to develop more detailed and challenging goals, which included financial measures in addition to the earnings per share component, could serve to reduce any potential disconnect between the short-term annual incentive award and personal and business unit performance. In addition, management discussed its belief that placing a greater emphasis on individual and business unit performance objectives would create a better incentive for participants to achieve goals that would help us to achieve our business and strategic initiatives, which, in the long term, would be expected to help us increase our profitability and increase shareholder returns.

Taking into consideration these discussions with management, in reviewing awards under the Short-Term Annual Incentive Plan at its October 2012 and February 2013 meetings, and in reviewing individual and business unit objectives for all senior executive officers, the Compensation Committee agreed that, in light of the Company’s significant operational objectives, including the construction of two new nuclear facilities, the Short-Term Annual Incentive Plan may not provide sufficient flexibility to appropriately reward individual participants for achieving or exceeding personal performance or business unit objectives, or to sufficiently penalize individual participants for failing to adequately achieve such objectives. The Committee also took into account the fact that, on management’s recommendation, the Committee had decreased the earnings per share payout of the 2011 Short-Term Annual Incentive Plan for all participants in 2012 by 25%, despite the fact that the earnings per share component of the award was earned at a higher level, because certain cost control objectives had not been achieved. The Committee further considered that, under management’s recommendation for changes to the Plan, at least 25% of most participants’ individual and business unit performance objectives under the Short-Term Annual Incentive Plan would be expected to be related to a financial objective, which would be in addition to the 25% of the award based on earnings per share targets.

Based on all of these considerations, the Compensation Committee approved management’s recommendation for the 2013 Plan to focus more on individual and business unit performance objectives and less on an earnings per share target.

Accordingly, for 2013, the Committee amended the Short-Term Annual Incentive Plan to provide that:

• 25% of the annual cash incentive payments under the Plan would be earned based on the extent to which we met designated earnings per share goals; and

• 75% of the payments would be earned based on our Named Executive Officers and the other participants achieving individual and business unit performance objectives. The Committee reviewed and approved all senior executive officer individual and business unit objectives.

The estimated possible payouts that could have been earned under the 2013 awards if performance objectives were met at threshold, target and maximum levels are set forth in the “2013 Grants of Plan-Based Awards” table on page 39. The 2013 Short-Term Annual Incentive Plan payouts based on our achieving our earnings per share target and business objectives, and our Named Executive Officers’ achieving their individual objectives, are reflected in the “Summary Compensation Table” on page 38 under the columns “Bonus” and “Non-Equity Incentive Plan Compensation.”

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Earnings per Share Component of 2013 Annual Incentive Award

Up to 25% of the total 2013 annual incentive award would be earned based on the extent to which we met our earnings per share goals as set forth below:

	40% of   EPS   Component   Earned at		60% of   EPS   Component   Earned at		80% of   EPS   Component   Earned at		100% of   EPS   Component   Earned at
Basic earnings per share	$	3.25	$	3.28	$	3.31	$	3.35

Our actual basic earnings per share for 2013 were $3.40, which resulted in our senior executive officers, and the other participants in the Short-Term Annual Incentive Plan, earning 100% of the earnings per share component of the 2013 annual incentive award.

Individual Strategic Objectives Component of 2013 Annual Incentive Award

The remaining 75% of the 2013 annual incentive award was based on our Named Executive Officers’ level of performance in helping us achieve our annual business objectives by achieving their individual performance objectives.

We achieved our business objectives and our senior executive officers achieved their individual strategic objectives. Accordingly, we made 100% payouts to our senior executive officers, including all of our Named Executive Officers. As further discussed below under the caption “—Discretionary Bonus Award,” we also made a discretionary bonus award equal to 25% of actual Short-Term Annual Incentive Plan awards to each of our senior executive officers, including our Named Executive Officers, as permitted by the Plan.

Individual Strategic Objectives on which 2013 Annual Incentive Awards were Based

The individual strategic objectives the Compensation Committee considered in determining short-term incentive awards for the Named Executive Officers were as follows:

Mr. Marsh’s award was based on his oversight of our new nuclear construction activities; developing for the Board of Directors a succession plan for key leaders; developing, for consideration by the Board of Directors, strategic plans for certain business units and future opportunities; and providing leadership to the senior executive officers.

Mr. Addison’s award was based on his successful monitoring of financial markets and obtaining external financings and refinancings as appropriate to meet our general corporate and new nuclear capital needs; development of a multiple year regulatory and financial plan for our largest subsidiary, SCE&G; and his development and implementation of targeted and specific recommendations for cost control strategies for 2013.

Mr. Byrne’s award was based on his oversight of a request for a proposal related to renewable resources; his oversight and management of the Base Load Review Act program for funding our new nuclear development; successful completion of an external audit of our transmission practices; and oversight of the performance of our fossil fuel units as certain of such plants transition to retirement.

Mr. Bullwinkel’s award was based on his oversight of successful implementation of improved operational efficiencies and improved margins for our two deregulated natural gas functions; resolution of long-standing contract and supply issues for a deregulated gas subsidiary; oversight of eligibility classification for a deregulated subsidiary’s ability to bid on government contracts; minimizing SCE&G’s capacity purchasing costs; and oversight of the expansion of a deregulated subsidiary’s consumer focused products and services.

Mr. Lindsay’s award was based on oversight of the filing of the Company’s Greenhouse Gas Emission Report with the Environmental Protection Agency; oversight of implementation of our environmental management system at an additional fossil/hydro facility; monitoring and oversight of compliance issues related to new environmental regulations; and oversight of corporate governance matters.

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Discretionary Bonus Award

A discretionary bonus award for eligible participants in our Short-Term Annual Incentive Plan was recommended to our Compensation Committee by our Chief Executive Officer, and both the Compensation Committee and the Board approved a 25% discretionary award. In making its decision to approve the discretionary award, the Compensation Committee and the Board took into account the fact that in 2013 the Company excelled in many diverse areas while successfully executing its new nuclear construction project. The Committee also considered that, unlike the annual incentive plans used by many of the Company’s peers, our Short-Term Annual Incentive Plan does not automatically pay out above target and instead relies on the Committee to exercise discretion in years in which performance supports an award greater than target. During the previous ten years, the Board has only exercised positive discretion to pay above target on three occasions. The Committee determined that, in order to follow the Company’s philosophy of paying for performance, discretionary awards for 2013 were appropriate to reward operational and administrative achievements, some of which were discussed in our Chairman’s Letter and 2013 Highlights and are as follows:

• We exceeded our publicly disclosed 2013 growth in earnings per share target goal of 4.5% by achieving earnings per share growth of 6.3% for the second consecutive year;

• Our operations and maintenance expenses were under budget by over $12 million, with no resulting negative impact on our commitment to safety, reliability, or customer service;

• In March 2013, we achieved an important and difficult milestone by being the first company in 30 years to complete a nuclear island basemat concrete pour in the United States. The historic milestone was achieved for V.C. Summer Station Unit 2 and was an accomplishment for our employees, our shareholders, and the nuclear industry. In November 2013, we also poured basemat concrete at V.C. Summer Station Unit 3; and

• We successfully reduced and redeployed certain of our workforce while pursuing important initiatives such as succession development, renewable fuels, and our new nuclear construction project. Our employees recognize the challenges facing our Company and the need for such workforce changes and have supported the efforts with no negative impact to safety, reliability, or customer service.

The Board also considered the positive results of 2013, some of which are listed above, along with the confidence the Company has in its long-term strategy to grow dividends fairly consistent with earnings growth, in making its determination to increase our common stock dividend rate. In February 2014, our Board of Directors raised the quarterly cash dividend on the Company’s common stock to 52 ¹/₂ cents per share from 50 ³/₄ cents per share, an increase of 3.5%. This action increases the indicated annual dividend rate to $2.10 per share from $2.03 per share.

In addition to the discretionary bonus award discussed above, one of our Named Executive Officers, Mr. Byrne, received the maximum discretionary award permitted by the Plan, representing 50% of his actual Short-Term Annual Incentive Plan target payout, to reward him for his efforts and achievements associated with our new nuclear construction project. Mr. Byrne’s leadership over the last several years and his project management for our new nuclear construction projects have been instrumental in moving the projects forward, and resulted in the historic company and industry milestone mentioned above. In addition to leading our new nuclear construction projects, Mr. Byrne continued to provide executive leadership for our other electric generation subsidiaries.

Long-Term Equity Compensation Plan

The potential value of long-term equity-based incentive compensation opportunities comprises a significant portion of the total compensation package for senior executive officers and key employees. The Compensation Committee believes that emphasizing this component of total compensation provides the appropriate long-range focus for senior executive officers and other key employees who are charged with responsibility for managing the Company and achieving success for our shareholders because it links the amount of their compensation to our business and financial performance.

A portion of each senior executive officer’s potential compensation consists of awards under the Long-Term Equity Compensation Plan. The types of long-term equity-based compensation the Compensation Committee may award under the Plan include incentive and non-qualified stock options, stock appreciation rights (either alone or in tandem with a related stock option), restricted stock, restricted stock units, performance units and performance

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shares. In recent years, our long-term equity-based awards have been in the form of performance shares and restricted stock units. These long-term equity-based awards are granted subject to satisfaction of specific performance goals and vesting schedules. For the 2011-2013, the 2012-2014, and the 2013-2015 performance periods, awards under the Long-Term Equity Compensation Plan consisted of 80% performance shares and 20% restricted stock units. The Committee has not awarded stock options since 2002 and has no plans to do so in the foreseeable future, and the Committee has not awarded any stock appreciation rights under the Plan.

We believe awards of performance shares align the interests of our executives with those of shareholders because the value of such awards is tied to our achieving financial and business goals that would be expected to affect the value of our common stock. We believe awards of restricted stock units align the interests of our executives with those of shareholders in that they ensure a long-term view of success, and we believe the three year vesting schedule aids in retention of executives. Although restricted stock units do not have the same risk of forfeiture for failure to meet performance thresholds associated with performance shares, they have no upside potential for payout above target level.

Performance Share Awards

For the past several years, the Compensation Committee has been granting performance share awards that are earned, if at all, over a three-year period that is measured in three one-year cycles based on comparative Total Shareholder Return (“TSR”) and earnings per share growth components. Performance share awards based on these components place a portion of executive compensation at risk because executives are compensated pursuant to the awards only when the objectives for TSR and earnings growth are met. Additionally, comparing our TSR to the TSR of a group of other companies reflects our recognition that investors could have invested their funds in other entities and measures how well we performed over time when compared to others in the group.

Performance share awards are denominated in shares of our common stock. The number of target performance shares into which awards are denominated is calculated by multiplying the Named Executive Officer’s base salary by a target percentage based on positions cited in the market survey data and dividing the product by a valuation factor applied to our opening stock price on the date of grant. The target percentage is derived from market survey data of the peer companies listed above under “Factors Considered in Setting Senior Executive Officer Compensation — Use of Market Surveys and Peer Group Data.” The valuation factor is provided to us by management’s compensation consultant and is intended as a means to establish a grant date salary equivalent value that takes into consideration such factors as dividend treatment, potential for maximum performance, and the treatment of awards upon termination. Performance share awards may be paid in stock or cash or a combination of stock and cash at the Committee’s discretion, but are most frequently paid in cash. In recent years, all payouts have been in cash. Payouts are based on the closing market price of our stock on the last business day of the three-year performance period.

2011-2013 Performance Share and Restricted Stock Unit Awards

For the 2011-2013 period, we granted awards under the Long-Term Equity Compensation Plan to each of the Named Executive Officers comprised of a combination of 80% performance shares and 20% restricted stock units.

Components of 2011-2013 Performance Share Awards

For the 2011-2013 period, the components on which we based performance share awards to senior executive officers were as follows: (1) our TSR relative to the TSR of a peer group of companies; and (2) a growth in earnings component based on growth in “GAAP-adjusted basic net earnings per share from operations” as that term is used in the Company’s periodic reports and external communications¹. TSR over the performance period was equal to the change in our common stock price, plus cash dividends paid on our common stock during the period, divided by the common stock price as of the beginning of the period. One half of target performance shares were based on the TSR component and one half were based on the earnings growth component.

¹  GAAP-adjusted basic net earnings per share from operations provides a consistent basis upon which to measure performance from year to year. GAAP-adjusted basic net earnings per share from operations has historically excluded from earnings such items as the effects arising from the Company’s adoption of new accounting guidance, the favorable settlement of certain litigation, and the effects of sales of certain investments. Management uses this measure when determining earnings guidance and growth projections and when making resource allocation and other budgetary and operational decisions.

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Performance measurement and award determinations for the performance shares for the 2011-2013 period were made on an annual basis with vesting and payment of awards being deferred until after the end of the three-year period. Accordingly, payouts under the 2011-2013 three-year period were earned for each year that performance goals were met during the three-year period, but vesting and payment were deferred until the end of the three-year period and were contingent upon the participant still being employed with us at the end of the three-year period, subject to certain exceptions in the event of retirement, death or disability. Payouts would also have been accelerated in the event of certain change in control events. See “ — Potential Payments Upon Termination or Change in Control.”

Performance Criteria for the 2011-2013 Performance Share Awards and Earned and Vested Awards for the 2011-2013 Performance Period

Payouts based on the TSR component of the 2011-2013 performance share awards were scaled according to our ranking against a peer group of utilities. Executives could earn threshold payouts (equal to 25% of target award) for each year of the three-year period in which we ranked at the 25^th percentile in relation to the peer group’s TSR performance for the one-year cycle. Target payouts (equal to 100% of target award) could be earned for each year of the three-year period in which we ranked at the 50^th percentile in relation to the peer group’s TSR performance for the one-year cycle. Maximum payouts (equal to 175% of target award) could be earned for each year of the three-year period in which our performance ranked at or above the 90^th percentile in relation to the peer group’s TSR performance for the one-year cycle. Payouts were scaled between 25% and 175% based on the actual percentile achieved. No payout could be earned if our performance was less than the 25^th percentile, and no payouts could exceed 175% of the target award. Threshold, target and maximum payouts at the 25^th, 50^th and 90^th percentiles were used because these generally matched the levels used by the companies in the market survey data.

The peer group of utilities with which we compared our TSR for the 2011-2013 period are set forth below:

Alliant Energy Corporation; Ameren Corporation; American Electric Power; Avista Corporation; Centerpoint Energy Inc.; CMS Energy Corporation; Consolidated Edison, Inc.; Dominion Resources, Inc.; DTE Energy Company; Duke Energy Corporation; Edison International; Entergy Corporation; Exelon Corporation; FirstEnergy Corp.; Great Plains Energy, Inc.; Hawaiian Electric Industries, Inc.; Integrys Energy Group, Inc.; NextEra, Inc.; NiSource Inc.; Northeast Utilities; NorthWestern Corporation; NV Energy; OGE Energy Corp.; Pepco Holdings, Inc.; PG&E Corporation; Pinnacle West Capital Corporation; PNM Resources, Inc.; PPL Corporation; Public Service Enterprise Group, Inc.; Southern Company; TECO Energy, Inc.; UIL Holdings Corporation; UNS Energy Corporation; Vectren Corporation; Westar Energy, Inc.; Wisconsin Energy Corporation; XCEL Energy, Inc.

The number of utilities included in the peer group used for TSR comparisons is larger than the number included in the market survey utility peer group we use for purposes of setting base salary and short- and long-term incentive targets because information about TSR is publicly available for a larger number of utilities. We include only utilities in the TSR peer group because we have assumed that shareholders would measure our performance against performance of other utilities in which they might have invested.

For the first, second and third years of the 2011-2013 period, our TSR was at the 22^nd , 66^th and 24^th percentiles, respectively, which resulted in no award on the TSR component being earned for the first and third years, and 130% being earned for the second year, vesting and payment of which was deferred until the end of the three-year period as discussed above. The overall payout of the TSR portion of the shares, which occurred in February 2014, was 43%.

With respect to the earnings growth component for the 2011-2013 period, executives could earn threshold payouts (equal to 25% of target award) for each year in the three-year period in which growth in GAAP-adjusted basic net earnings per share from operations equaled 1%. Executives could earn target payouts (equal to 100% of target award) for each year in which such growth equaled 3%, and maximum payouts (equal to 175% of target award) for each year in which such growth equaled or exceeded 7%. Payouts were scaled between 25% and 175% based on the actual growth in GAAP-adjusted basic net earnings per share from operations. No payouts could be earned for any year in which growth in GAAP-adjusted basic net earnings per share from operations was less than 1%, and no payouts could exceed 175% of target award.

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For the first, second and third years of the 2011-2013 period, our growth in GAAP-adjusted basic net earnings per share from operations was 3.1%, 6.3% and 6.3%, respectively, which resulted in a 101.9%, 161.9% and 161.9% award on the earnings per share component being earned for the respective years, payment of which was deferred until the end of the three-year period as discussed above. The overall payout of the GAAP-adjusted basic net earnings per share from operations portion of the shares, which occurred in February 2014, was 142%.

The overall payout of the total TSR and GAAP-adjusted basic net earnings per share from operations components of the performance share awards for the 2011-2013 cycle, which occurred in February 2014, was 93%, and is reflected in the “2013 Option Exercises and Stock Vested” table on page 41.

2011-2013 Restricted Stock Unit Awards

The 2011-2013 restricted stock unit awards were granted on February 11, 2011, and were based on the fair market value of our common stock on the date of grant. The restricted stock units were subject to a three-year vesting period, and were not performance based. The restricted stock units did not have voting rights prior to vesting, and were subject to forfeiture in the event of termination of employment prior to the end of the vesting period, subject to exceptions for retirement, death, disability, or change in control. Information about vesting of the restricted stock unit award component of the 2011-2013 awards is reflected in the “2013 Option Exercises and Stock Vested” table on page 41. The restricted stock units were paid in cash in February 2014.

2012-2014 Performance Share and Restricted Stock Unit Awards

For the 2012-2014 period, we again granted awards under the Long-Term Equity Compensation Plan to each of the Named Executive Officers comprised of a combination of 80% performance shares and 20% restricted stock units.

Components of 2012-2014 Performance Share Awards

The components on which we based the 2012-2014 performance share awards were the same as those used for the 2011-2013 period, consisting of one half to be earned based on our level of achieving TSR targets and the remaining one half to be earned based on our level of achieving growth in GAAP-adjusted basic net earnings per share from operations targets. Performance measurement and award determination for the performance shares for the 2012-2014 period will also be made on an annual basis with payment of awards being deferred until after the end of the three-year period on the same terms as for the 2011-2013 awards. See “Components of 2011-2013 Performance Share Awards.”

Performance Criteria for the 2012-2014 Performance Share Awards and Earned Awards for the 2012 and 2013 Performance Cycles

For the half of performance shares based on our level of achieving TSR targets, the performance criteria, and the TSR peer group of utilities used for the 2012-2014 period are again the same as those used for the 2011-2013 period as discussed above under “Performance Criteria for the 2011-2013 Performance Share Awards and Earned and Vested Awards for the 2011-2013 Performance Period,” unless a company could no longer be included due to a merger, dissolution or other similar transaction.

For the first and second years of the 2012-2014 period, our TSR was at the 66^th and 24^th percentiles, which resulted in an award on the TSR component being earned at 130% for the first year and no award being earned for the second year.

For the half of performance shares based on our level of achieving growth in GAAP-adjusted basic net earnings per share from operations targets, the performance criteria for threshold and maximum award payouts are again the same for the 2012-2014 period as those used for the 2011-2013 period as discussed above under “Performance Criteria for the 2011-2013 Performance Share Awards and Earned and Vested Awards for the 2011-2013 Performance Period.” However, the performance criteria for target award payout was increased to 4%.

For each of the first and second years of the 2012-2014 period, our growth in GAAP-adjusted basic net earnings per share from operations was 6.3%, which resulted in 157.5% of awards on the earnings per share component being earned for each year, payment of which will be deferred until the end of the three-year period as discussed above.

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See the “Outstanding Equity Awards at 2013 Fiscal Year-End” table on page 40 for information about the number and value of performance shares that have been earned for the first and second years of the 2012-2014 period, but have not vested.

2012-2014 Restricted Stock Unit Awards

The 2012-2014 restricted stock unit awards were granted on February 15, 2012, and were based on the fair market value of our common stock on the date of grant. The restricted stock units are subject to a three-year vesting period, and are not performance based. The restricted stock units have the same terms as the 2011-2013 restricted stock units as discussed above under “2011-2013 Restricted Stock Unit Awards.” Information about the restricted stock unit awards outstanding at the end of 2013 is provided in the “Outstanding Equity Awards at 2013 Fiscal Year-End” table on page 40.

2013-2015 Performance Share and Restricted Stock Unit Awards

For the 2013-2015 period, we again granted awards under the Long-Term Equity Compensation Plan to each of the Named Executive Officers comprised of a combination of 80% performance shares and 20% restricted stock units. See the “2013 Grants of Plan-Based Awards” table on page 39.

Components of 2013-2015 Performance Share Awards

The components on which we based the 2013-2015 performance share awards were the same as those used for the 2011-2013 and 2012-2014 periods, consisting of one half to be earned based on our level of achieving TSR targets and the remaining one half to be earned based on our level of achieving growth in GAAP-adjusted basic net earnings per share from operations targets. Performance measurement and award determination for the performance shares for the 2013-2015 period will also be made on an annual basis with payment of awards being deferred until after the end of the three-year period on the same terms as for the 2011-2013 and 2012-2014 awards. See “Components of 2011-2013 Performance Share Awards” and “Components of 2012-2014 Performance Share Awards”

Performance Criteria for the 2013-2015 Performance Share Awards and Earned Awards for the 2013 Performance Cycle

For the half of performance shares based on our level of achieving TSR targets, the performance criteria, and the TSR peer group of utilities used for the 2013-2015 period are again the same as those used for the 2011-2013 and 2012-2014 periods as discussed above under “Performance Criteria for the 2011-2013 Performance Share Awards and Earned and Vested Awards for the 2011-2013 Performance Period” and “Performance Criteria for the 2012-2014 Performance Share Awards and Earned Awards for the 2012 and 2013 Performance Cycles,” unless a company could no longer be included due to a merger, dissolution or other similar transaction.

For the first year of the 2013-2015 period, our TSR was at the 24^th percentile, which resulted no award being earned on the TSR component for the first year.

For the half of performance shares based on our level of achieving growth in GAAP-adjusted basic net earnings per share from operations targets, executives could earn threshold payouts (equal to 25% of target award) for each year in the three-year period in which growth in GAAP-adjusted basic net earnings per share from operations equaled 1%. Executives could earn target payouts (equal to 100% of target award) for each year in which such growth equaled 4.5%, and maximum payouts (equal to 175% of target award) for each year in which such growth equaled or exceeded 8%. Potential payouts were scaled between 25% and 175% based on the actual growth in GAAP-adjusted basic net earnings per share from operations. No payouts could be earned for any year in which growth in GAAP-adjusted basic net earnings per share from operations was less than 1%, and no payouts could exceed 175% of target award.

For the first year of the 2013-2015 period, our growth in GAAP-adjusted basic net earnings per share from operations was 6.3%, which resulted in a 138.6% award on the earnings per share component being earned for the first year, payment of which will be deferred until the end of the three-year period as discussed above.

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See the “Outstanding Equity Awards at 2013 Fiscal Year-End” table on page 40 for information about the number and value of performance shares that have been earned for the first year of the 2013-2015 period, but have not vested.

2013-2015 Restricted Stock Unit Awards

The 2013-2015 restricted stock unit awards were granted on February 20, 2013, and were based on the fair market value of our common stock on the date of grant. The restricted stock units are subject to a three-year vesting period, and are not performance based. The restricted stock units have the same terms as the 2011-2013 restricted stock units as discussed above under “2011-2013 Restricted Stock Unit Awards.” Information about the restricted stock unit awards granted for the 2013 three-year period is provided in the “2013 Grants of Plan-Based Awards” table on page 39. See also the “Outstanding Equity Awards at 2013 Fiscal Year-End” table on page 40.

2014 Compensation

At its February 2014 meeting, the Board, on recommendation of the Compensation Committee, increased the base salaries of Messrs. Marsh, Addison, Byrne, and Lindsay by 5%. The salary adjustments did not result in compensation materially different from 2013 compensation. In addition, Messrs. Addison and Byrne’s positions were reclassified to a higher level based on market data provided by management’s compensation consultant, and therefore they received the following increases: Short-Term Annual Incentive Plan target opportunities increased from 70% to 75% of base salary, and Long-Term Equity Compensation Plan target opportunities increased from 160% to 175% of base salary.

Retirement and Other Benefit Plans

We currently sponsor the following retirement benefit plans:

• A tax qualified defined benefit retirement plan (the “Retirement Plan”) (closed to new employees and rehired employees as of December 31, 2013);

• A nonqualified defined benefit Supplemental Executive Retirement Plan (the “SERP”) (closed to new employees and rehired employees as of December 31, 2013);

• A tax qualified defined contribution plan (the “401(k) Plan” also known as the “SCANA Corporation Stock Purchase-Savings Plan”); and

• A nonqualified defined contribution Executive Deferred Compensation Plan (the “EDCP”).

All employees who have met eligibility requirements may participate in the Retirement Plan and the 401(k) Plan.

The SERP and the EDCP are designed to provide a benefit to senior executive officers who participate in the Retirement Plan or 401(k) Plan (our tax qualified retirement plans) and whose participation in those tax qualified plans at the same percentage of salary as all other employees is otherwise limited by government regulation. The SERP and EDCP participants are provided with the benefits to which they would have been entitled under the Retirement Plan or 401(k) Plan had their participation not been limited. At present, certain senior executive officers, including the Named Executive Officers, are participants in the SERP and/or EDCP. The SERP is described under the caption “Potential Payments Upon Termination or Change in Control — Retirement Benefits — Supplemental Executive Retirement Plan” on page 48 and the EDCP is described under the caption “2013 Nonqualified Deferred Compensation — Executive Deferred Compensation Plan” on page 43. We provide the SERP and the EDCP benefits because they allow our senior executive officers the opportunity to defer the same percentage of their compensation as other employees. We also believe, based on market survey data, that these plans may be necessary to make our senior executive officer retirement benefits competitive.

As of December 31, 2013, the Retirement Plan and the SERP were both closed to new employees and rehired employees. Current participants in the Retirement Plan and the SERP who continue to meet eligibility requirements will continue to earn benefits until December 31, 2023. Effective January 1, 2024, participants will no longer earn any future benefit accruals under these plans except that participants under the cash balance formula will continue to earn interest credits.

We also provide other benefits such as medical, dental, life and disability insurance, which are available to all of our employees. In addition, we provide our executive officers with additional long-term disability insurance and retiree medical and term life insurance.

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Termination, Severance and Change in Control Arrangements

Our retirement and benefit plans include provisions that provide for payments to our senior executive officers, including our Named Executive Officers, in the event of a change in control of our Company. These arrangements, including the triggering events for payments and possible payment amounts, are described under the caption “Potential Payments Upon Termination or Change in Control.” We believe that these arrangements are not uncommon for executives at the level of our Named Executive Officers and senior executive officer participants, including executives of the companies included in our compensation market survey information. We believe these arrangements are important factors in attracting and retaining our senior executive officers by assuring them financial and employment status protections in the event control of our Company changes. We believe such assurances of financial and employment protections help free executives from personal concerns over their futures, and thereby, can help to align their interests more closely with those of shareholders in negotiating transactions that could result in a change in control.

Perquisites

We provide limited perquisites to senior executive officers as summarized below.

Company Aircraft

The Company owns two turboprop aircraft for the use of officers and managers in their travels to various operations throughout our service areas, as well as to meet with regulatory bodies, industry groups, financial groups, and to conduct other Company business. Our senior executive officers may use our aircraft for business purposes on a non-exclusive basis. Our aircraft are also used, if necessary, to transport directors to and from meetings and committee meetings of the Board of Directors. Spouses or close family members of directors and senior executive officers occasionally accompany a director or senior executive officer on the aircraft when the director or executive officer is flying for our business purposes. On rare occasions, a senior executive officer may use our aircraft for personal use that is not in connection with a business purpose. We impute income to the executive for certain expenses related to such use.

For purposes of determining total 2013 compensation, we valued the aggregate incremental cost of the personal use of our aircraft, if any, using a method that takes into account the variable expenses associated with operating the aircraft, which variable expenses are only incurred if the planes are flying. The following items are included in our aggregate incremental cost: aircraft fuel and oil expenses per hour of flight; maintenance, parts and external labor (inspections and repairs) per hour of flight; landing/parking/flight planning services expenses; crew travel expenses; supplies and food.

Medical Examinations

We offer all employees who participate in our health plans a preventive annual medical examination at no cost. Additionally, in order that we might plan for any executive-level health related retirements or resignations, we also provide each of our senior executive officers the opportunity to have a comprehensive annual medical examination from Duke University, the Medical University of South Carolina, or the physician of his or her choice.

Security Systems

We offer installation and provide monitoring of home security systems for our senior executive officers. Because we operate a nuclear facility and provide essential services to the public, we believe we have a duty to help assure uninterrupted and safe operations by protecting the safety and security of our senior executive officers. We provide such installation and monitoring at more than one home for some senior executive officers.

Other Perquisites

We provide a taxable allowance to our senior executive officers for financial counseling services, including tax preparation and estate planning services. We value this benefit based on the actual charges incurred. We also pay the fees and monthly dues for club memberships for senior executive officers which are used exclusively for business purposes. We sometimes invite spouses to accompany directors and senior executive officers to our quarterly Board meetings because we believe social gatherings of directors and senior executive officers in connection with these meetings increases collegiality.

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Accounting and Tax Treatment of Compensation and Other Discussion

Deductibility of Executive Compensation

Section 162(m) of the Internal Revenue Code establishes a limit on the tax deductibility of annual compensation in excess of $1,000,000 for certain senior executive officers, including the Named Executive Officers. Certain performance-based compensation approved by shareholders is not subject to the tax deduction limit. Our Long-Term Equity Compensation Plan is currently qualified so that most performance-based awards under that Plan constitute compensation that is not subject to Section 162(m). Our Annual Short-Term Incentive Plan does not meet Section 162(m) tax deductibility requirements. To maintain flexibility in compensating senior executive officers in a manner designed to promote various corporate goals, the Compensation Committee has not adopted a policy that all compensation must be tax deductible. Because Mr. Marsh’s salary exceeds the $1,000,000 threshold, we may not deduct a portion of his compensation for tax purposes. The Compensation Committee considered these tax effects in connection with its deliberations on senior executive compensation.

Accounting for Stock Based Compensation

Beginning January 1, 2006, we began accounting for stock based compensation in accordance with the requirements of FASB ASC Topic 718. All stock based compensation awards since 2009 have been accounted for as liability awards.

Financial Restatement

Although we have never experienced such a situation, our Board of Directors’ policy would be to consider, on a case-by-case basis, a retroactive adjustment to any cash or equity-based incentive compensation paid to our senior executive officers where payment was conditioned on achievement of certain financial results that were subsequently restated or otherwise adjusted in a manner that would reduce the size of a prior award or payment.

Security Ownership Guidelines for Executive Officers

At its February 2010 meeting, the Board established minimum stock ownership guidelines for senior executive officers with a title of Senior Vice President and above. The Board determined that the Chief Executive Officer will be required to hold a minimum of five times his or her annual base salary in the form of SCANA Corporation common stock and that all other senior executive officers will be required to hold a minimum of three times their annual base salary in the form of SCANA Corporation common stock. Current senior executive officers have until February 2015 to acquire sufficient shares to meet the minimum stock ownership requirement. Any newly elected Chief Executive Officer or Senior Vice President has a period of five years from their election to meet the required minimum ownership requirement. Once a senior executive officer complies with the minimum ownership guidelines, compliance will not be jeopardized by fluctuations in the price of the Company’s common stock as long as the senior executive officer has not sold shares of the Company’s common stock which were included to meet the minimum ownership requirements. The Compensation Committee of the Board monitors compliance with the policy, and also has the authority to grant a temporary waiver of the minimum share ownership requirement upon demonstration by the senior executive officer that, due to a financial hardship or other good reason, he or she cannot meet the requirement. For purposes of meeting the applicable guidelines, the following will be considered SCANA common stock: (i) shares held directly; (ii) shares held in any defined contribution, employee stock ownership plan or other stock-based plan; (iii) performance shares/units under an incentive or base salary deferral plan; (iv) performance shares/units earned and/or deferred in any long-term incentive plan account; and (v) vested and unvested restricted stock and restricted stock unit awards. The Board directed that the Company institute appropriate policies and administrative processes to ensure the minimums are effectively monitored and communicated with annual reports to the Compensation Committee. As of February 2014, all senior executive officers met the minimum stock ownership guidelines or were expected to meet the guidelines by the compliance dates.

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Non-binding Shareholder Advisory Votes on Executive Compensation and Frequency of Votes on Executive Compensation

Pursuant to the requirements of Section 14A of the Securities Exchange Act of 1934 and related Securities and Exchange Commission regulations, at our 2011 Annual Meeting of Shareholders, we submitted to our shareholders a non-binding advisory vote on approval of executive compensation and a non-binding advisory vote on whether to hold the non-binding advisory vote on executive compensation every year, every two years, or every three years. At its August 2011 meeting, and again at its February 2012 and February 2013 meetings, the Compensation Committee took into consideration that 93.8% of the shares voting on the non-binding advisory vote on executive compensation had voted in favor of the proposal, and the Committee concluded that no material changes to executive compensation decisions and policies were necessary in 2012 or 2013.

The Committee also took into consideration that, of the shares voting on the non-binding advisory vote on frequency of the vote on executive compensation, more shares voted in favor of a three year frequency than on either of the other frequency alternatives, and, accordingly, has set the current frequency of the non-binding advisory vote on executive compensation at three years. Accordingly, at the 2014 Annual Meeting, shareholders are again being given the opportunity to vote on a non-binding advisory proposal relating to executive compensation. See “Proposal 4 — Advisory (non-binding) Vote to Approve Executive Compensation.” After the 2014 Annual Meeting, the next non-binding advisory vote on executive compensation will be at the 2017 annual meeting. At the 2017 annual meeting, shareholders will also be given the opportunity to vote on a non-binding advisory proposal relating to the frequency of the vote on executive compensation.

Compensation Committee Report

The Compensation Committee has reviewed and discussed with management the “Compensation Discussion and Analysis” included in this proxy statement. Based on that review and discussion, the Compensation Committee recommended to our Board of Directors that the “Compensation Discussion and Analysis” be included in our Annual Report on Form 10-K for the year ended December 31, 2013 for filing with the Securities and Exchange Commission, and included in this proxy statement.

Maceo K. Sloan (Chairman)

Joshua W. Martin, III

James M. Micali

Harold C. Stowe

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SUMMARY COMPENSATION TABLE

The following table summarizes information about compensation paid or accrued during 2013, 2012 and 2011 to our Chief Executive Officer, our Chief Financial Officer and our three next most highly compensated executive officers. (As noted in the “Compensation Discussion and Analysis,” we refer to these persons as our Named Executive Officers.)

Name and Principal Position (a)	Year (b)		Salary ($)(1) (c)		Bonus ($)(2) (d)		Stock Awards ($)(3) (e)		Option Awards ($) (f)		Non-Equity Incentive Plan Compensation ($)(4) (g)		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(5) (h)		All Other Compensation ($)(6) (i)		Total ($) (j)
K. B. Marsh, Chief Executive Officer, President and Chief Operating Officer		2013 2012 2011	$ $ $	1,052,765 1,000,000 703,923	$ $ $	239,159 225,000 0	$ $ $	2,700,702 2,460,789 1,319,474		— — —	$ $ $	956,637 900,000 344,866	$ $ $	149,158 295,453 176,145	$ $ $	136,066 88,740 68,947	$ $ $	5,234,487 4,969,982 2,613,355
J. E. Addison, Executive Vice President and Chief Financial Officer		2013 2012 2011	$ $ $	547,010 516,462 459,952	$ $ $	96,469 91,875 0	$ $ $	896,367 826,840 576,631		— — —	$ $ $	385,875 330,750 209,250	$ $ $	34,635 149,679 85,830	$ $ $	83,066 50,066 50,813	$ $ $	2,043,422 1,965,672 1,382,476
S. A. Byrne, Executive Vice President		2013 2012 2011	$ $ $	547,010 516,462 463,077	$ $ $	192,938 183,750 0	$ $ $	896,366 826,840 576,631		— — —	$ $ $	385,875 367,500 209,250	$ $ $	39,631 170,360 97,692	$ $ $	71,031 49,483 49,768	$ $ $	2,132,851 2,114,395 1,396,418
G. J. Bullwinkel, Jr., Senior Vice President		2013 2012 2011	$ $ $	480,000 477,865 465,000	$ $ $	72,000 72,000 0	$ $ $	634,189 614,191 576,631		— — —	$ $ $	288,000 288,000 209,250	$ $ $	163,104 185,864 205,457	$ $ $	56,775 69,417 73,474	$ $ $	1,694,068 1,707,337 1,529,812
R. T. Lindsay Senior Vice President and General Counsel		2013 2012 2011	$ $ $	404,369 380,019 348,077	$ $ $	61,215 57,750 0	$ $ $	539,224 492,632 381,934		— — —	$ $ $	244,860 231,000 144,375	$ $ $	66,699 54,447 50,723	$ $ $	64,982 37,104 37,530	$ $ $	1,381,349 1,252,952 962,639

(1) Base salary increases for our Named Executive Officers are discussed under “— Compensation Discussion and Analysis — Base Salaries” beginning on page 26.

(2) No discretionary bonus awards under the Short-Term Annual Incentive Plan were granted for 2011. For 2012, discretionary bonus awards were granted as permitted under the 2012 Short-Term Annual Incentive Plan. For 2013, discretionary bonus awards were granted as permitted under the 2013 Short-Term Annual Incentive Plan, which are discussed in further detail under “— Compensation Discussion and Analysis — Short-Term Annual Incentive Plan — Discretionary Bonus Award” on page 29.

(3) The information in this column relates to performance share and restricted stock unit awards (liability awards) under the Long-Term Equity Compensation Plan. This Plan is discussed under “— Compensation Discussion and Analysis — Long-Term Equity Compensation Plan” beginning on page 29. The amounts in this column represent the aggregate grant date fair value of the awards computed in accordance with FASB ASC Topic 718. The value of performance share awards is based on the probable outcome of performance conditions, consistent with the estimate of aggregate compensation cost to be recognized over the service period determined as of the grant date under FASB ASC Topic 718, excluding the effect of estimated forfeitures. For 2013, the maximum values of the performance shares, assuming the highest levels of performance, would be as follows: Mr. Marsh $3,796,150; Mr. Addison $1,259,980; Mr. Byrne $1,259,980; Mr. Bullwinkel $891,430; and Mr. Lindsay $757,916. The assumptions made in the valuation of stock awards are set forth in Note 9 to our audited financial statements for the year ended December 31, 2013, which are included in our Form 10-K for the year ended December 31, 2013, and with this proxy statement.

(4) Payouts under the Short-Term Annual Incentive Plan were based on the levels at which we achieved growth in earnings per share and business objectives and at which our Named Executive Officers achieved their individual and business unit financial and strategic objectives, as discussed in further detail under “ — Compensation Discussion and Analysis — Short-Term Annual Incentive Plan” beginning on page 26.

(5) The aggregate change in the actuarial present value of each Named Executive Officer’s accumulated benefits under SCANA’s Retirement Plan and Supplemental Executive Retirement Plan from the pension plan measurement date used for financial statement reporting purposes with respect to the audited financial statements for the prior completed fiscal year to the pension plan measurement date used for financial statement reporting purposes with respect to the audited financial statements for the covered fiscal year shown, determined using interest rate and mortality rate assumptions consistent with those used in our financial statements. These plans are discussed under “— Compensation Discussion and Analysis — Retirement and Other Benefit Plans” beginning on page 34, “— Defined Benefit Retirement Plan” beginning on page 42, “— Supplemental Executive Retirement Plan” beginning on page 42, and “— Potential Payments Upon Termination or Change in Control — Retirement Benefits — Supplemental Executive Retirement Plan” beginning on page 48.

(6) Includes all other compensation paid to each Named Executive Officer, including Company contributions to the 401(k) Plan and the Executive Deferred Compensation Plan, imputed income for disability insurance and aircraft use, if any, tax reimbursements with respect to perquisites or other personal benefits, life insurance premiums on policies owned by Named Executive Officers, and perquisites that exceeded $10,000 in the aggregate for any Named Executive Officer. For 2013, the Company contributions to defined contribution plans were as follows: Mr. Marsh $130,375; Mr. Addison $58,057; Mr. Byrne $65,775; Mr. Bullwinkel $50,400; and Mr. Lindsay $59,147. Perquisites that exceeded an aggregate of $10,000 for any of our Named Executive Officers were as follows: Mr. Addison $18,445, consisting of financial planning services, an executive physical, residential security system capital installation and improvement costs, and maintenance and monitoring of residential security systems. Life insurance premiums on policies owned by the Named Executive Officers did not exceed $10,000 for any Named Executive Officer.

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2013 GRANTS OF PLAN-BASED AWARDS

The following table sets forth information about each grant of an award made to a Named Executive Officer under our compensation plans during 2013.

		Estimated Possible Payouts Under Non-Equity Incentive Plan Awards(1)						Estimated Future Payouts Under Equity Incentive Plan Awards(2)(4)
Name	Grant Date	Threshold ($)		Target ($)		Maximum ($)		Threshold (#)		Target (#)		Maximum (#)		All Other Stock Awards: Number of Shares of Stock or Units (#)(3)(4)		All Other Option Awards: Number of Securities Underlying Options (#)		Exercise or Base Price of Option Awards ($/Sh)		Grant Date Fair Value of Stock and Option Awards ($)(5)
(a)	(b)	(c)		(d)		(e)		(f)		(g)		(h)		(i)		(j)		(k)		(l)
K. B. Marsh	2-20-2013	$	478,319		$956,637	$	1,434,956
	2-20-2013								11,124		44,497		77,870				—		—	$	2,169,229
	2-20-2013														10,902					$	531,473
J. E. Addison	2-20-2013	$	192,938	$	385,875	$	578,813
	2-20-2013								3,692		14,769		25,846				—		—	$	719,989
	2-20-2013														3,618					$	176,378
S. A. Byrne	2-20-2013	$	192,938	$	385,875	$	578,813
	2-20-2013								3,692		14,769		25,846				—		—	$	719,989
	2-20-2013														3,618					$	176,378
G. J. Bullwinkel, Jr.	2-20-2013	$	144,000	$	288,000	$	432,000
	2-20-2013								2,612		10,449		18,286				—		—	$	509,389
	2-20-2013														2,560					$	124,800
R. T. Lindsay	2-20-2013	$	122,430	$	244,860	$	367,290
	2-20-2013								2,221		8,884		15,547				—		—	$	433,095
	2-20-2013														2,177					$	106,129

(1) The amounts in columns (c), (d) and (e) represent the threshold, target and maximum awards that could have been paid under the 2013 Short-Term Annual Incentive Plan if performance criteria were met. Awards were based 25% on our achieving earnings per share objectives and 75% on our Named Executive Officers achieving business and individual performance objectives. For 2013, our basic earnings per share were $3.40 and all of the Named Executive Officers met all of their individual and business unit strategic objectives. Accordingly, awards were earned at 100% on the earnings per share portion of the award (25% of total target award shown in column (d)), and at 100% on the individual and business unit strategic objectives portion of the award (75% of total target award shown in column (d)), resulting in 100% of the total target award shown in column (d) being earned for all Named Executive Officers. A discussion of the 2013 Short-Term Annual Incentive Plan is included under “— Compensation Discussion and Analysis — Short-Term Annual Incentive Plan” beginning on page 26. See also, “—Compensation Discussion and Analysis — Short-Term Annual Incentive Plan — Discretionary Bonus Award” beginning on page 29.

(2) Represents total potential future payouts of the 2013-2015 performance share awards under the Long-Term Equity Compensation Plan. Payout of performance share awards at the end of the 2013-2015 Plan period will be dictated by our performance against pre-determined measures of TSR and growth in GAAP-adjusted basic net earnings per share from operations for each year of the three-year period. Awards for the 2013 performance cycle were not earned for the TSR portion of the award, but were earned at 138.6% for the growth in GAAP-adjusted basic net earnings per share from operations portion of the award. The 2013 earned award with respect to the GAAP-adjusted basic net earnings per share from operations portions of the 2013-2015 performance share awards will not vest until the end of the 2013-2015 period. See — “Compensation Discussion and Analysis — Long-Term Equity Compensation Plan — Components of 2013-2015 Performance Share Awards,” and “— Performance Criteria for the 2013-2015 Performance Share Awards and Earned Awards for the 2013 Performance Cycle” beginning on page 33.

(3) Represents restricted stock unit awards. Restricted stock unit awards are primarily time based and vest after three years if the Named Executive Officer is still employed by us at that date, subject to exceptions for retirement, death, disability, or a change in control. See — “Compensation Discussion and Analysis — Long-Term Equity Compensation Plan — 2013-2015 Restricted Stock Unit Awards” beginning on page 34.

(4) A discussion of the components of the performance share and restricted stock unit awards is included under — “Compensation Discussion and Analysis — Long-Term Equity Compensation Plan — Components of 2013-2015 Performance Share Awards,” and “— Performance Criteria for the 2013-2015 Performance Share Awards and Earned Awards for the 2013 Performance Cycle,” and “— 2013-2015 Restricted Stock Unit Awards” beginning on page 33.

(5) The grant date fair value of restricted stock unit awards is computed in accordance with FASB ASC Topic 718. The grant date fair value of performance share awards is based on the probable outcome of the performance conditions, consistent with the estimate of aggregate compensation cost to be recognized over the performance period determined as of the grant date under FASB ASC Topic 718, excluding the effect of estimated forfeitures.

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OUTSTANDING EQUITY AWARDS AT 2013 FISCAL YEAR-END

The following table sets forth certain information regarding equity incentive plan awards for each Named Executive Officer outstanding as of December 31, 2013.

		Stock Awards
Name (a)	Date of    Grant	Number of   Shares or   Units   of Stock That   Have Not   Vested   (#)(1)   (g)		Market   Value of   Shares or   Units of   Stock   That Have   Not   Vested   ($)(2)   (h)		Equity   Incentive Plan   Awards:   Number of   Unearned   Shares, Units or   Other Rights   That Have   Not Vested   (#)(3)(4)  (i)		Equity   Incentive Plan   Awards: Market   or Payout Value of   Unearned Shares,    Units or Other   Rights That Have   Not Vested   ($)(2)(4)   (j)
K. B. Marsh	2-20-13		10,279	$	482,393		29,665	$	1,392,178
	2-20-13		10,902	$	511,631
	2-15-12		32,506	$	1,525,507		14,608	$	685,553
	2-15-12		11,176	$	524,490
J. E. Addison	2-20-13		3,412	$	160,125		9,846	$	462,073
	2-20-13		3,618	$	169,793
	2-15-12		10,923	$	512,616		4,909	$	230,379
	2-15-12		3,755	$	176,222
S. A. Byrne	2-20-13		3,412	$	160,125		9,846	$	462,073
	2-20-13		3,618	$	169,793
	2-15-12		10,923	$	512,616		4,909	$	230,379
	2-15-12		3,755	$	176,222
G. J. Bullwinkel, Jr.	2-20-13		2,414	$	113,289		6,966	$	326,914
	2-20-13		2,560	$	120,141
	2-15-12		8,112	$	380,696		3,647	$	171,154
	2-15-12		2,789	$	130,888
R. T. Lindsay	2-20-13		2,052	$	96,300		5,923	$	277,966
	2-20-13		2,177	$	102,167
	2-15-12		6,507	$	305,374		2,925	$	137,270
	2-15-12		2,237	$	104,982

(1) The awards granted on February 20, 2013 represent performance shares and restricted stock units awarded under the 2013-2015 performance period of the Long-Term Equity Compensation Plan that have been earned, but have not vested. TSR for the first year of the 2013 – 2015 performance period was at the 24^th percentile, resulting in no award being earned on the TSR portion of the performance awards for the first year of the performance period. The growth in GAAP-adjusted basic net earnings per share from operations portion of the performance awards for the first year of the 2013-2015 performance period was earned based on our achieving growth in GAAP-adjusted basic net earnings per share from operations of 6.3% and resulted in the award being earned at 138.6% of target for the first year of the period. The performance shares will vest on December 31, 2015, if the Named Executive Officer is still employed by us at that date, subject to exceptions for retirement, death, disability, or change in control. The restricted stock units will vest January 1, 2016, if the Named Executive Officer is still employed by us at that date, subject to exceptions for retirement, death, disability, or change in control.

The awards granted on February 15, 2012 represent performance shares and restricted stock units awarded under the 2012-2014 performance period of the Long-Term Equity Compensation Plan that have been earned, but have not vested. The TSR portion of the performance awards for the first year of the 2012-2014 performance period was earned at 130%, representing TSR at the 66^th percentile. TSR for the second year of the 2012–2014 performance period was at the 24^th percentile, resulting in no award being earned on the TSR portion of the performance awards for the second year of the performance period. The growth in GAAP-adjusted basic net earnings per share from operations portion of the performance awards for the first and second years of the 2012-2014 performance period was earned based on our achieving growth in GAAP-adjusted basic net earnings per share from operations of 6.3% and resulted in the award being earned at 157.5% of target for both years of the period. The performance shares will vest on December 31, 2014, if the Named Executive Officer is still employed by us at that date, subject to exceptions for retirement, death, disability, or change in control. The restricted stock units will vest January 1, 2015, if the Named Executive Officer is still employed by us at that date, subject to exceptions for retirement, death, disability, or change in control.

(2) The market value of these awards is based on the closing market price of our common stock on the New York Stock Exchange on December 31, 2013 of $46.93.

40

(3) The awards granted on February 20, 2013 represent performance shares remaining in the 2013-2015 performance period that have not been earned. Assuming the performance criteria are met and the reported payout levels are sustained, these performance shares will vest on December 31, 2015, subject to exceptions for retirement, death, disability, or change in control. The awards granted on February 15, 2012 represent performance shares remaining in the 2012-2014 performance period that have not been earned. Assuming the performance criteria are met and the reported payout levels are sustained, these performance shares will vest on December 31, 2014, subject to exceptions for retirement, death, disability, or change in control.

(4) For each of the 2014 and 2015 cycles remaining in the 2013-2015 awards, performance shares tracking against TSR (50% of performance share award) are projected to result in a less than threshold payout. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the threshold performance measure for the 2014 and 2015 TSR portions of the performance shares. Performance shares tracking against growth in GAAP-adjusted basic net earnings per share from operations (50% of performance share award) for the 2014 and 2015 cycles remaining in the 2013-2015 awards are projected to result in a greater than target payout. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the maximum performance measure for the 2014 and 2015 growth in GAAP-adjusted basic net earnings per share from operations portions of the performance shares.

For the 2014 cycle remaining in the 2012-2014 awards, performance shares tracking against TSR (50% of performance share award) are projected to result in a less than threshold payout. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the 2012-2014 threshold performance measure for the 2014 TSR portion of the performance shares. Performance shares tracking against growth in GAAP-adjusted basic net earnings per share from operations (50% of performance share award) for the 2014 cycle remaining in the 2012-2014 awards are projected to result in a greater than target payout. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the maximum performance measure for the 2014 growth in GAAP-adjusted basic net earnings per share from operations portion of the performance shares.

2013 OPTION EXERCISES AND STOCK VESTED

The following table sets forth information about stock awards that vested for each Named Executive Officer during 2013. None of our employees, including the Named Executive Officers, currently hold stock options.

	Option Awards				Stock Awards
Name (a)	Number of  Shares   Acquired on   Exercise  (#)  (b)		Value Realized   on Exercise  ($)  (c)		Number of  Shares  Acquired on   Vesting (#)(1)    (d)		Value Realized  on Vesting   ($)(1)   (e)
K. B. Marsh		—		—		23,018 6,275	$ $	1,080,235 295,364
J. E. Addison		—		—		10,058 2,742	$ $	472,022 129,066
S. A. Byrne		—		—		10,058 2,742	$ $	472,022 129,066
G. J. Bullwinkel, Jr.		—		—		10,058 2,742	$ $	472,022 129,066
R. T. Lindsay		—		—		6,663 1,816	$ $	312,695 85,479

(1) Represents the 2011-2013 performance share awards and restricted stock unit awards that vested at the end of the three-year vesting period. For a discussion of these awards, see “Long-Term Equity Compensation Plan — Performance Criteria for the 2011-2013 Performance Share Awards and Earned and Vested Awards for the 2011-2013 Performance Period” and “— 2011-2013 Restricted Stock Unit Awards.” Dollar amounts in column (e) are calculated by multiplying the number of performance shares shown in column (d) by the closing price of SCANA common stock on the vesting date (December 31, 2013) and by multiplying the number of shares of restricted stock units by the opening price of SCANA common stock on the vesting date. In addition to the amounts above, on the vesting date, each Named Executive Officer also received dividend equivalents on the shares listed above.

41

PENSION BENEFITS

The following table sets forth certain information relating to our Retirement Plan and Supplemental Executive Retirement Plan.

Name (a)	Plan Name (b)	Number of Years Credited Service (#)(1) (c)	Present Value of Accumulated Benefit ($)(1)(2) (d)		Payments During Last Fiscal Year($) (e)
K. B. Marsh	SCANA Retirement Plan	29	$	752,168	$	0
	SCANA Supplemental Executive Retirement Plan	29	$	1,173,626	$	0
J. E. Addison	SCANA Retirement Plan	22	$	321,777	$	0
	SCANA Supplemental Executive Retirement Plan	22	$	373,374	$	0
S. A. Byrne	SCANA Retirement Plan	18	$	296,420	$	0
	SCANA Supplemental Executive Retirement Plan	18	$	586,971	$	0
G. J. Bullwinkel, Jr.	SCANA Retirement Plan	42	$	1,639,723	$	0
	SCANA Supplemental Executive Retirement Plan	42	$	1,310,265	$	0
R. T. Lindsay	SCANA Retirement Plan	4	$	104,872	$	0
	SCANA Supplemental Executive Retirement Plan	4	$	127,350	$	0

(1) Computed as of December 31, 2013, the plan measurement date used for financial statement reporting purposes.

(2) Present value calculation determined using current account balances for each Named Executive Officer as of December 31, 2013, based on assumed retirement at normal retirement age (specified as age 65) and other assumptions as to valuation method, interest rate, discount rate and other material factors as set forth in Note 8 to our audited financial statements for the year ended December 31, 2013, which are included in our Form 10-K for the year ended December 31, 2013, and with this Proxy Statement.

The SCANA Retirement Plan is a tax qualified defined benefit plan and the Supplemental Executive Retirement Plan is a nonqualified deferred compensation plan. The Plans provide for full vesting after three years of service or after reaching age 65. All Named Executive Officers are fully vested in both Plans. As of December 31, 2013, the Retirement Plan and the SERP were both closed to new employees and rehired employees. Current participants in the Retirement Plan and the SERP who continue to meet eligibility requirements will continue to earn benefits until December 31, 2023. Effective January 1, 2024, participants will no longer earn any future benefit accruals under these plans except that participants under the cash balance formula will continue to earn interest credits.

Defined Benefit Retirement Plan

The SCANA Retirement Plan (the “Retirement Plan”) is a tax qualified defined benefit retirement plan. The plan uses a mandatory cash balance benefit formula for employees hired on or after January 1, 2000. Effective July 1, 2000, SCANA employees hired prior to January 1, 2000 were given the choice of remaining under the Retirement Plan’s final average pay formula or switching to the cash balance formula. All the Named Executive Officers participate under the cash balance formula of the Retirement Plan.

The cash balance formula is expressed in the form of a hypothetical account balance. Account balances are increased monthly by interest and compensation credits. The interest rate used for accumulating account balances is determined annually based on 30-year treasury securities and the applicable segment rates determined under Internal Revenue Code Section 417(c)(3)(D) calculated using the rates for December of the previous calendar year. Compensation credits equal 5% of compensation up to the Social Security wage base and 10% of compensation in excess of the Social Security wage base.

Supplemental Executive Retirement Plan

In addition to the Retirement Plan, we provide a Supplemental Executive Retirement Plan (the “SERP”) for certain eligible employees, including the Named Executive Officers. The SERP is an unfunded plan that provides for benefit payments in addition to benefits payable under the qualified Retirement Plan in order to replace benefits lost in the Retirement Plan because of Internal Revenue Code maximum benefit limitations. The SERP is discussed under the caption “ — Potential Payments Upon Termination or Change in Control — Retirement Benefits” beginning on page 48, and under the caption “ — Compensation Discussion and Analysis — Retirement and Other Benefit Plans” beginning on page 34.

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2013 NONQUALIFIED DEFERRED COMPENSATION

The following table sets forth information with respect to the Executive Deferred Compensation Plan:

Name	Executive   Contributions   in Last FY   ($)(1)		Registrant   Contributions   in Last FY   ($)(1)		Aggregate   Earnings in   Last FY   ($)(1)		Aggregate   Withdrawals   Distributions   ($)		Aggregate   Balance at   Last FYE   ($)(1)
(a)	(b)		(c)		(d)		(e)		(f)
K. B. Marsh	$	115,366	$	115,076	$	122,495		—	$	1,911,561
J. E. Addison	$	42,878	$	42,757	$	102,987		—	$	737,165
S. A. Byrne	$	50,596	$	50,475	$	62,594		—	$	1,183,349
G. J. Bullwinkel, Jr.	$	35,100	$	35,100	$	110,132		—	$	2,531,102
R. T. Lindsay	$	455,829	$	43,847	$	78,131		—	$	1,121,389

(1) The amounts reported in columns (b) and (c) are reflected in columns (c) and (i), respectively, of the Summary Compensation Table. No amounts in column (d) are reported, or have been previously reported, in the Summary Compensation Table as there were no above market or preferential earnings credited to any Named Executive Officer’s account. The portions of the amounts reported in column (f), that represent Named Executive Officer and Company contributions, were previously reported in columns (c) and (i), respectively, of the 2012 and 2011 Summary Compensation Tables in the following amounts: Mr. Marsh $131,176 for 2012, $219,610 for 2011; Mr. Addison $56,809 for 2012, $55,252 for 2011; Mr. Byrne $56,809 for 2012, $58,117 for 2011; Mr. Bullwinkel $52,385 for 2012, $59,880 for 2011; and Mr. Lindsay $350,481 for 2012, $88,126 for 2011. For prior years, amounts would have been included in the Summary Compensation Table when required by the rules of the Securities and Exchange Commission.

Executive Deferred Compensation Plan

The Executive Deferred Compensation Plan (the “EDCP”) is a nonqualified deferred compensation plan in which our senior executive officers, including Named Executive Officers, may participate if they choose to do so. Each participant may elect to defer up to 25% of that part of his or her eligible earnings (as defined in the SCANA Corporation Stock Purchase-Savings Plan, our 401(k) plan), that exceeds the limitation on compensation otherwise required under Internal Revenue Code Section 401(a)(17), without regard to any deferrals or the foregoing of compensation. For 2013, participants could defer eligible earnings in excess of $255,000. In addition, a participant may elect to defer up to 100% of any performance share award for the year under our Long-Term Equity Compensation Plan. We match the amount of compensation deferred by each participant up to 6% of the participant’s eligible earnings (excluding performance share awards) in excess of the Internal Revenue Code Section 401(a)(17) limit.

We record the amount of each participant’s deferred compensation and the amount we match in a ledger account and credit a rate of return to each participant’s ledger account based on hypothetical investment alternatives chosen by the participant. The internal committee that administers the EDCP designates various hypothetical investment alternatives from which the participants may choose. Using the results of the hypothetical investment alternatives chosen, we credit each participant’s ledger account with the amount it would have earned if the account amount had been invested in that alternative. If the chosen hypothetical investment alternative loses money, the participant’s ledger account is reduced by the corresponding amount. All amounts credited to a participant’s ledger accounts continue to be credited or reduced pursuant to the chosen investment alternatives until such amounts are paid in full to the participant or his or her beneficiary. No actual investments are made. The investment alternatives are only used to generate a rate of increase (or decrease) in the ledger accounts, and amounts paid to participants are solely our obligation. In connection with this Plan, the Board has established a grantor trust (known as the “SCANA Corporation Executive Benefit Plan Trust”) for the purpose of accumulating funds to satisfy the obligations we incur under the EDCP. At any time prior to a change in control we may transfer assets to the trust to satisfy all or part of our obligations under the EDCP. Notwithstanding the establishment of the trust, the right of participants to receive future payments is an unsecured claim against us. The trust has been partially funded with respect to ongoing deferrals and Company matching funds since October 2001.

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In 2013, the Named Executive Officers’ ledger accounts were credited with earnings or losses based on the following hypothetical investment alternatives and rates of returns:

Wells Fargo Stable Return Fund C (+1.45%); PIMCO Total Return ( -1.92%); Dodge & Cox Common Stock (+40.55%); Janus Research Fund (+35.36%); T. Rowe Price Mid Cap Value (+31.54%); Managers AMG TimesSquare Mid Cap Growth Fund (+36.72%); RS Partners (+42.68%); ING Small Cap Opportunities (+37.94%); American Funds Europacific Growth (+18.22%); Dodge & Cox International Stock Fund (+26.31%); SCANA Corporation Stock (+7.24%); Vanguard 500 Index Fund (+32.33%); Vanguard Target Retirement Income (+5.87%); Vanguard Target Retirement 2015 (+13.00%); Vanguard Target Retirement 2020 (+15.85%); Vanguard Target Retirement 2025 (+18.14%); Vanguard Target Retirement 2030 (+20.49%); Vanguard Target Retirement 2035 (+22.82%); Vanguard Target Retirement 2040 (+24.37%); Vanguard Target Retirement 2045 (+24.37%); Vanguard Target Retirement 2050 (+24.34%); Vanguard Target Retirement 2055 (+24.33%); Vanguard Target Retirement 2060 (+24.35%).

The measures for calculating interest or other plan earnings are based on the investments chosen by the manager of each investment vehicle, except the SCANA Corporation stock, the earnings of which are based on the value of our common stock.

The hypothetical investment alternatives may be changed at any time on a prospective basis by the participants in accordance with the telephone, electronic, and written procedures and forms adopted by the committee for use by all participants on a consistent basis.

Participants may elect the deferral period for each separate deferral made under the Plan. Participants may elect to defer payment of eligible earnings or performance share awards until their termination of employment or until a date certain prior to termination of employment. Any post-2004 deferrals and hypothetical earnings thereon must be payable at the same date certain if the date certain payment alternative is chosen. In accordance with procedures established by the committee, with respect to any deferrals to a date certain, a participant may request that the committee approve an additional deferral period of at least 60 months as to any post-2004 deferrals and hypothetical earnings thereon, or at least 12 months as to any pre-2005 deferrals and hypothetical earnings thereon. The request must be made at least 12 months before the expiration of the date certain deferral period for which an additional deferral period is being sought. Notwithstanding a participant’s election of a date certain deferral period or any modification thereof as discussed above, deferred amounts will be paid, or begin to be paid as soon as practicable after the earliest to occur of participant’s death, termination of employment, or, with respect to pre-2005 deferrals and hypothetical earnings thereon, disability. “Termination of employment” is defined by the EDCP as any termination of the participant’s employment relationship with us and any of our affiliates, and, with respect to post-2004 deferrals and hypothetical earnings thereon, the participant’s separation from service from us and our affiliates as determined under Internal Revenue Code section 409A and the guidelines issued thereunder.

Participants also elect the manner in which their deferrals and hypothetical earnings thereon will be paid. For amounts earned and vested after January 1, 2005, distribution and withdrawal elections are subject to Internal Revenue Code Section 409A. All amounts payable at a date certain prior to participant’s termination of employment, death, or, with respect to pre-2005 deferrals and hypothetical earnings thereon, disability, must be paid in the form of a single cash payment. Payments made after termination of employment, death, or, with respect to pre-2005 deferrals and hypothetical earnings thereon, disability, will also be paid in the form of a single cash payment. Instead of a single cash payment, a participant may, however, elect to have all amounts payable as a result of termination of employment after attainment of age 55, death while employed and after attainment of age 55, or, with respect to pre-2005 deferrals and hypothetical earnings thereon, termination of employment due to disability, paid in the form of annual installments over a period not to exceed five years with respect to post-2004 deferrals and hypothetical earnings thereon or 15 years with respect to pre-2005 deferrals and hypothetical earnings thereon.

Payments as a result of a separation from service of post-2004 deferrals and hypothetical earnings thereon to persons who are “specified employees” under our procedures adopted in accordance with Internal Revenue Code Section 409A and guidance thereunder (certain officers and executive officers) must be deferred until the earlier of (i) the first day of the seventh month following the participant’s separation from service or (ii) the date of the participant’s death.

A participant may request and receive, with the approval of the committee, an acceleration of the payment of some or all of the participant’s ledger account due to severe financial hardship as the result of certain extraordinary

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and unforeseeable circumstances arising as a result of events beyond the individual’s control. With respect to pre-2005 deferrals and hypothetical earnings thereon, a participant may also obtain a single lump sum payment of this ledger account on an accelerated basis by forfeiting 10% of the amount accelerated or by making the election, not less than 12 months prior to the date on which the accelerated payment is to be made, to accelerate the payment to a date not less than 12 months before the payment otherwise would be made. Additionally, the Plan provides for the acceleration of payments following a change in control of our Company. The change in control provisions are discussed under “— Potential Payments Upon Termination or Change in Control  — Change in Control Arrangements.”

Potential Payments Upon Termination or Change in Control

Change in Control Arrangements

Effective December 31, 2009, we terminated the SCANA Corporation Key Executive Severance Benefits Plan, which provided for payment of benefits immediately upon a change in control unless the Plan was terminated prior to the change in control. Also as of December 31, 2009, we amended our change in control benefits to eliminate excise tax gross ups.

Triggering Events for Payments under the Supplementary Key Executive Severance Benefits Plan

The SCANA Corporation Supplementary Key Executive Severance Benefits Plan (the “Supplementary Severance Plan”) provides for payments to our senior executive officers in connection with a change in control of our Company. The Supplementary Severance Plan provides for payment of benefits if, within 24 months after a change in control, we terminate a senior executive officer’s employment without just cause or if the senior executive officer terminates his or her employment for good reason.

Our Supplementary Severance Plan is intended to advance the interests of our Company by providing highly qualified executives and other key personnel with an assurance of equitable treatment in terms of compensation and economic security and to induce continued employment with the Company in the event of certain changes in control. We believe that an assurance of equitable treatment will enable valued executives and key personnel to maintain productivity and focus during a period of significant uncertainty inherent in change in control situations. We also believe that compensation plans of this type aid the Company in attracting and retaining the highly qualified professionals who are essential to our success. The structure of the plan, and the benefits which might be paid in the event of a change in control, are reviewed as part of the Compensation Committee’s annual review of tally sheets for each senior executive officer.

The Supplementary Severance Plan provides that a “change in control” will be deemed to occur under the following circumstances:

• if any person or entity becomes the beneficial owner, directly or indirectly, of 25% or more of the combined voting power of the outstanding shares of our common stock;

• if, during a consecutive two-year period, a majority of our directors cease to be individuals who either (i) were directors on the Board at the beginning of such period, or (ii) became directors after the beginning of such period but whose election by the Board, or nomination for election by our shareholders, was approved by at least two-thirds of the directors then still in office who either were directors at the beginning of such period, or whose election or nomination for election was previously so approved;

• if (i) we consummate a merger or consolidation of our Company with another corporation (except a merger or consolidation in which our outstanding voting shares prior to such transaction continue to represent at least 80% of the combined voting power of the surviving entity’s outstanding voting shares after such transaction), or (ii) our shareholders approve a plan of complete liquidation of our Company, or an agreement to sell or dispose of all or substantially all of our assets; or

• if we consummate the sale of the stock of, or our shareholders approve a plan of complete liquidation of, or an agreement for the sale or disposition of substantially all of the assets of South Carolina Electric & Gas Company, Carolina Gas Transmission Corporation or any of our other subsidiaries that the Board designates to be a material subsidiary. This last provision would constitute a change in control only with respect to participants exclusively assigned to the affected subsidiary.

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As noted above, benefits under the Supplementary Severance Plan would be triggered if, within 24 months after a change in control, we terminated the senior executive officer’s employment without just cause or if the senior executive officer terminated his or her employment for good reason. Under the plan, we would be deemed to have “just cause” for terminating the employment of a senior executive officer if he or she:

• willfully and continually failed to substantially perform his or her duties after we made demand for substantial performance;

• willfully engaged in conduct that is demonstrably and materially injurious to us; or

• were convicted of a felony or certain misdemeanors.

A senior executive officer would be deemed to have “good reason” for terminating his or her employment if, after a change in control, without his or her consent, any one or more of the following occurred:

• a material diminution in his or her base salary;

• a material diminution in his or her authority, duties, or responsibilities;

• a material diminution in the authority, duties, or responsibilities of the supervisor to whom he or she is required to report, including a requirement that he or she report to one of our officers or employees instead of reporting directly to the Board;

• a material diminution in the budget over which he or she retains authority;

• a material change in the geographic location at which he or she must perform services; or

• any other action or inaction that constitutes a material breach by us of the agreement under which he or she provides services.

Potential Benefits Payable under the Supplementary Severance Plan

The benefits we would be required to pay our senior executive officers under the Supplementary Severance Plan immediately upon the occurrence of a triggering event subsequent to a change in control are as follows:

• an amount intended to approximate 2.5 times the sum of: (i) his or her annual base salary (before reduction for certain pre-tax deferrals) in effect as of the change in control, plus (ii) his or her full targeted annual incentive opportunity in effect as of the change in control;

• an amount equal to the participant’s full targeted annual incentive opportunity in effect under each existing annual incentive plan or program for the year in which the change in control occurs;

• if the participant’s benefit under the SERP is determined using the final average pay formula under the Retirement Plan, an amount equal to the present lump sum value of the actuarial equivalent of his or her accrued benefit under the Retirement Plan and the SERP through the date of the change in control, calculated as though he or she had attained age 65 and completed 35 years of benefit service as of the date of the change in control, and as if his or her final average earnings under the Retirement Plan equaled the amount determined after applying cost-of-living increases to his or her annual base salary from the date of the change in control until the date he or she would reach age 65, and without regard to any early retirement or other actuarial reductions otherwise provided in any such plan (this benefit will be offset by the actuarial equivalent of the participant’s benefit provided by the Retirement Plan and the Participant’s benefit under the SERP);

• if the participant’s benefit under the SERP is determined using the cash balance formula under the Retirement Plan, an amount equal to the present value as of the date of the change in control of his or her accrued benefit, if any, under our SERP, determined prior to any offset for amounts payable under the Retirement Plan, increased by the present value of the additional projected pay credits and periodic interest credits that would otherwise accrue under the plan (based on the plan’s actuarial assumptions) assuming that he or she remained employed until reaching age 65, and reduced by his or her cash balance account under the Retirement Plan, and further reduced by an amount equal to his or her benefit under the SERP;

• an amount equal to the value of all amounts credited to each participant’s EDCP ledger account as of the date of the change in control, plus interest on the benefits payable under the EDCP at a rate equal to the sum of the prime interest rate as published in the Wall Street Journal on the most recent publication date prior to

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the date of the change in control plus 3%, calculated through the end of the month preceding the month in which the benefits are distributed, reduced by the value of his or her benefit under the EDCP as of the date of the change in control; and

• an amount equal to the projected cost for medical, long-term disability and certain life insurance coverage for three years following the change in control as though he or she had continued to be our employee.

In addition to the benefits above (unless their agreements with us provide otherwise), our senior executive officers would also be entitled to benefits under our other plans in which they participate as follows:

• a benefit distribution under the Long-Term Equity Compensation Plan equal to 100% of the target awards for all performance periods not completed as of the date of the change in control, if any; and

• any amounts previously earned, but not yet paid, under the terms of any of our other plans or programs.

Calculation of Benefits Potentially Payable to our Named Executive Officers under the Supplementary Severance Plan if a Triggering Event had Occurred as of December 31, 2013

The Supplementary Severance Plan provides that, if (i) we had been subject to a change in control in the past 24 months, and (ii) as of December 31, 2013, either we had terminated the employment of any of our Named Executive Officers without just cause or they had terminated their employment for good reason, such terminated Named Executive Officer would have been immediately entitled to all of the benefits outlined below, together with interest, calculated as outlined above under “ — Potential Benefits Payable under the Supplementary Severance Plan,” on his EDCP account balance. The actual amount of any such additional interest payment would depend upon the date the change in control occurred.

Mr. Marsh would have been entitled to the following: an amount equal to 2.5 times his 2013 base salary and target short-term incentive award — $5,048,918; an amount equal to the excess payable under the SERP as calculated under the assumptions described above — $1,177,954; an amount equal to insurance continuation benefits for three years — $64,161; an amount equal to the difference between target and actual annual incentive award under the Short-Term Annual Incentive Plan — $0 (for 2013, the Short-Term Annual Incentive Plan paid out above target, resulting in no additional benefit); an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan for all performance periods not completed — $3,223,059; and an amount equal to the value of 100% of his restricted stock units under the Long-Term Equity Compensation Plan — $818,975. The total value of these change in control benefits would have been $10,333,067. In addition, Mr. Marsh would have been paid amounts previously earned, but not yet paid, as follows: 2013 actual short-term annual incentive award — $1,147,965; 2013 actual long-term equity award — $1,549,892; EDCP account balance — $1,911,560; SERP and Retirement Plan account balances — $2,058,259; vacation accrual — $43,437; as well as his 401(k) Plan account balance.

Mr. Addison would have been entitled to the following: an amount equal to 2.5 times his 2013 base salary and target short-term incentive award — $2,342,813; an amount equal to the excess payable under the SERP as calculated under the assumptions described above — $729,210; an amount equal to insurance continuation benefits for three years — $70,953; an amount equal to the difference between target and actual annual incentive award under the Short-Term Annual Incentive Plan — $0 (for 2013, the Short-Term Annual Incentive Plan paid out above target, resulting in no additional benefit); an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan for all performance periods not completed — $1,200,798; and an amount equal to the value of 100% of his restricted stock units under the Long-Term Equity Compensation Plan — $304,904. The total value of these change in control benefits would have been $4,648,678. In addition, Mr. Addison would have been paid amounts previously earned, but not yet paid, as follows: 2013 actual short-term annual incentive award — $463,050; 2013 actual long-term equity award — $677,248; EDCP account balance — $737,164; SERP and Retirement Plan account balances — $781,134; vacation accrual — $6,626; as well as his 401(k) Plan account balance.

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Mr. Byrne would have been entitled to the following: an amount equal to 2.5 times his 2013 base salary and target short-term incentive award — $2,342,813; an amount equal to the excess payable under the SERP as calculated under the assumptions described above — $735,798; an amount equal to insurance continuation benefits for three years — $53,277; an amount equal to the difference between target and actual annual incentive award under the Short-Term Annual Incentive Plan — $0 (for 2013, the Short-Term Annual Incentive Plan paid out above target, resulting in no additional benefit); an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan for all performance periods not completed — $1,200,798; and an amount equal to the value of 100% of his restricted stock units under the Long-Term Equity Compensation Plan — $304,904. The total value of these change in control benefits would have been $4,637,590. In addition, Mr. Byrne would have been paid amounts previously earned, but not yet paid, as follows: 2013 actual short-term annual incentive award — $463,050; 2013 actual long-term equity award — $677,248; EDCP account balance — $1,183,348; SERP and Retirement Plan account balances — $984,539; vacation accrual — $37,103; as well as his 401(k) Plan account balance.

Mr. Bullwinkel would have been entitled to the following: an amount equal to 2.5 times his 2013 base salary and target short-term incentive award — $1,920,000; an amount equal to the excess payable under the SERP as calculated under the assumptions described above — $0; an amount equal to insurance continuation benefits for three years — $52,155; an amount equal to the difference between target and actual annual incentive award under the Short-Term Annual Incentive Plan — $0 (for 2013, the Short-Term Annual Incentive Plan paid out above target, resulting in no additional benefit); an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan for all performance periods not completed — $1,023,074; and an amount equal to the value of 100% of his restricted stock units under the Long-Term Equity Compensation Plan — $259,570. The total value of these change in control benefits would have been $3,254,799. In addition, Mr. Bullwinkel would have been paid amounts previously earned, but not yet paid, as follows: 2013 actual short-term annual incentive award — $345,600; 2013 actual long-term equity award — $677,248; EDCP account balance — $2,531,102; SERP and Retirement Plan account balances — $2,949,988; vacation accrual — $14,769; as well as his 401(k) Plan account balance.

Mr. Lindsay would have been entitled to the following: an amount equal to 2.5 times his 2013 base salary and target short-term incentive award — $1,632,400; an amount equal to the excess payable under the SERP as calculated under the assumptions described above — $81,438; an amount equal to insurance continuation benefits for three years — $52,335; an amount equal to the difference between target and actual annual incentive award under the Short-Term Annual Incentive Plan — $0 (for 2013, the Short-Term Annual Incentive Plan paid out above target, resulting in no additional benefit); an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan for all performance periods not completed — $749,378; and an amount equal to the value of 100% of his restricted stock units under the Long-Term Equity Compensation Plan — $190,207. The total value of these change in control benefits would have been $2,705,759. In addition, Mr. Lindsay would have been paid amounts previously earned, but not yet paid, as follows: 2013 actual short-term annual incentive award — $293,832; 2013 actual long-term equity award — $448,624; EDCP account balance — $1,121,389; SERP and Retirement Plan account balances — $235,486; vacation accrual — $9,673; as well as his 401(k) Plan account balance.

Retirement Benefits

Supplemental Executive Retirement Plan

The Supplemental Executive Retirement Plan (the “SERP”) is an unfunded nonqualified defined benefit plan. The SERP was established for the purpose of providing supplemental retirement income to certain of our employees, including the Named Executive Officers, whose benefits under the Retirement Plan are limited in accordance with the limitations imposed by the Internal Revenue Code on the amount of annual retirement benefits payable to employees from qualified pension plans or on the amount of annual compensation that may be taken into account for all qualified plan purposes, or by certain other design limitations on determining compensation under the Retirement Plan.

Subject to the terms of the SERP, a participant becomes eligible to receive benefits under the SERP upon termination of his or her employment with us (or at such later date as may be provided in a participant’s agreement with us), if the participant has become vested in his or her accrued benefit under the Retirement Plan prior to termination of employment. However, if a participant is involuntarily terminated following or incident to a change in

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control and prior to becoming fully vested in his or her accrued benefit under the Retirement Plan, the participant will automatically become fully vested in his benefit under the SERP and a benefit will be payable under the SERP. The term “change in control” has the same meaning in the SERP as in the Supplementary Severance Plan. See the discussion under “—Change in Control Arrangements.”

The amount of any benefit payable to a participant under the SERP will depend upon whether the participant’s benefit under the SERP is determined using the final average pay formula under the Retirement Plan or the cash balance pay formula under the Retirement Plan. All of our Named Executive Officers participate under the cash balance pay formula of the Retirement Plan. Unless otherwise provided in a participant agreement, the amount of any SERP benefit payable pursuant to the SERP to a participant whose benefit is determined using the final average pay formula under the Retirement Plan will be determined at the time the participant first becomes eligible to receive benefits under the SERP and will be equal to the excess, if any, of:

• the monthly pension amount that would have been payable at normal retirement age or, if applicable, delayed retirement age under the Retirement Plan (as such terms are defined under the Retirement Plan), to the participant determined based on his or her compensation and disregarding the Internal Revenue Code limitations and any reductions due to the participant’s deferral of compensation under any of our nonqualified deferred compensation plans (other than the SERP), over

• the monthly pension amount payable to the participant at normal retirement age or, if applicable, delayed retirement age under the Retirement Plan.

The calculation of this benefit assumes that payment is made to the participant at normal retirement age or, if applicable, delayed retirement age under the Retirement Plan, and is calculated using the participant’s years of benefit service and final average earnings as of the date of the participant’s termination of employment.

Unless otherwise provided in a participant agreement, the amount of any benefit payable pursuant to the SERP as of any determination date to a participant whose SERP benefit is determined using the cash balance formula under the Retirement Plan will be equal to:

• the benefit that otherwise would have been payable under the Retirement Plan as of the determination date, based on his or her compensation and disregarding the Internal Revenue Code limitations, minus

• the Participant’s benefit determined under the Retirement Plan as of the determination date.

For purposes of the SERP, “compensation” is defined as determined under the Retirement Plan, without regard to the limitation under Section 401(a)(17) of the Internal Revenue Code, including any amounts of compensation otherwise deferred under any non-qualified deferred compensation plan (excluding the SERP).

The benefit payable to a participant under the SERP will be paid, or commence to be paid, as of the first day of the calendar month following the date the participant first becomes eligible to receive a benefit under the SERP (the “payment date”). The form of payment upon distribution of benefits under the SERP will depend upon whether the benefit constitutes a “grandfathered benefit” or a “non-grandfathered benefit.” For purposes of the SERP, “grandfathered benefit” means the vested portion of the benefit payable under the SERP assuming the participant’s determination date is December 31, 2004, increased with interest credits (for a participant whose benefit under the SERP is determined using the cash balance formula under the Retirement Plan) and earnings (for a participant whose benefit under the SERP is determined using the final average pay formula under the Retirement Plan) at the rates determined under the Retirement Plan through any later determination date. A participant’s grandfathered benefit is governed by the terms of the SERP in effect as of October 3, 2004 and will be determined in a manner consistent with Internal Revenue Code Section 409A and the guidance thereunder. “Non-grandfathered benefit” means the portion of the benefit payable under the SERP that exceeds the grandfathered benefit.

With respect to grandfathered benefits, the participant may elect, in accordance with procedures we establish, to receive a distribution of such grandfathered benefit in either of the following two forms of payment:

• a single sum distribution of the value of the participant’s grandfathered benefit under the SERP determined as of the last day of the month preceding the payment date; or

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• a lifetime annuity benefit with an additional death benefit payment as follows: a lifetime annuity that is the actuarial equivalent of the participant’s single sum amount which provides for a monthly benefit payable for the participant’s life, beginning on the payment date. In addition to this life annuity, commencing on the first day of the month following the participant’s death, his or her designated beneficiary will receive a benefit of 60% of the amount of the participant’s monthly payment continuing for a 15 year period. If, however, the beneficiary dies before the end of the 15 year period, the lump sum value of the remaining monthly payments of the survivor benefit will be paid to the beneficiary’s estate. The participant’s life annuity will not be reduced to reflect the “cost” of providing the 60% survivor benefit feature. “Actuarial equivalent” is defined by the SERP as equality in value of the benefit provided under the SERP based on actuarial assumptions, methods, factors and tables that would apply under the Retirement Plan under similar circumstances.

With respect to non-grandfathered benefits, a participant whose benefit under the SERP is determined using the final average pay formula under the Retirement Plan will receive a distribution of his or her benefit under the SERP as a single sum distribution equal to the actuarial equivalent present value (at the date of the participant’s termination of employment) of the participant’s SERP benefit determined as of normal retirement age, reflecting any terms under the Retirement Plan applicable to early retirement benefits if the participant is eligible for such early retirement benefits.

Except as otherwise provided below, a participant whose benefit under the SERP is determined using the cash balance formula under the Retirement Plan had the opportunity to elect on or before January 1, 2009 to receive a distribution of his non-grandfathered benefit in one of the following forms of payment:

• a single sum distribution of the value of the participant’s non-grandfathered benefit determined as of the last day of the month preceding the payment date;

• an annuity for the participant’s lifetime that is the actuarial equivalent of the participant’s single sum amount, and that commences on the payment date; or

• an annuity that is the actuarial equivalent of the participant’s single sum amount, that commences on the payment date, and that provides payments for the life of the participant and, upon his or her death, continues to pay an amount equal to 50%, 75% or 100% (as elected by the participant prior to benefit commencement) of the annuity payment to the contingent annuitant designated by the participant at the time the election is made.

A participant whose benefit under the SERP is determined using the cash balance formula under the Retirement Plan who first became an eligible employee after 2008, and who was not eligible to participate in the EDCP before becoming eligible to participate in the SERP, may elect at any time during the first 30 days following the date he becomes an eligible employee to receive a distribution of his non-grandfathered benefit in one of the forms specified above.

Participants whose benefits under the SERP are determined using the cash balance formula under the Retirement Plan will receive distributions under the SERP as follows:

• If a participant has terminated employment before attaining age 55, the participant’s non-grandfathered benefit will be paid in the form of a single sum distribution of the value of the participant’s non-grandfathered benefit determined as of the last day of the month preceding the payment date.

• If a participant has terminated employment after attaining age 55, and the value of the participant’s non-grandfathered benefit does not exceed $100,000 at the time of such termination of employment, such benefit shall be paid in the form of a single sum distribution of the value of the participant’s non-grandfathered benefit determined as of the last day of the month preceding the payment date.

• In the absence of an effective election, and assuming that the provisions in the two bullet points immediately above do not apply, non-grandfathered SERP benefits owed to the participant will be paid in the form of an annuity for the participant’s lifetime that is the actuarial equivalent of the participant’s single sum amount, and that commences on the payment date.

A participant who elects, or is deemed to have elected, either the straight life annuity or the joint and survivor annuity described above may, in accordance with procedures established by the Committee, change his election to the other annuity option at any time prior to the payment date.

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Unless otherwise provided in a participant agreement, if a participant dies on or after July 1, 2000 and before the payment date, a single sum distribution equal to the value of the participant’s benefit that otherwise would have been payable under the SERP will be paid to the participant’s designated beneficiary as soon as administratively practicable following the participant’s death.

Notwithstanding the foregoing, distribution of any non-grandfathered benefit that is made as a result of a termination of employment for a reason other than death, to persons who are “specified employees” under Internal Revenue Code Section 409A and guidance thereunder (basically, executive officers) must be deferred until the earlier of (i) the first day of the seventh month following the participant’s termination of employment or (ii) the date of the participant’s death.

If a participant is involuntarily terminated following or incident to a change in control, the participant shall automatically become fully vested in his or her benefit under the SERP and such benefits shall become payable.

Calculation of Benefits Potentially Payable to our Named Executive Officers under the SERP if a Triggering Event had Occurred as of December 31, 2013

The lump sum or annuity amounts that would have been payable under the SERP to each of our Named Executive Officers if they had become eligible for benefits as of December 31, 2013 are set forth below. Also set forth below are the payments that would have been made to each Named Executive Officer’s designated beneficiary if the officer had died December 31, 2013.

For Mr. Marsh, the lump sum amount would have been $1,254,353. Alternatively, Mr. Marsh could have elected to receive a lump sum of $883,782 as of December 31, 2013 and monthly payments of $2,124 commencing January 1, 2014 for the remainder of his lifetime. In the event Mr. Marsh had been eligible to receive benefits and had elected to receive the aforementioned monthly annuity, his designated beneficiary would have received monthly payments of $1,274 for up to 15 years upon Mr. Marsh’s death. If Mr. Marsh had died December 31, 2013 before becoming eligible for benefits, his beneficiary would have been entitled to the full lump sum payment of $1,254,353.

For Mr. Addison, the lump sum amount would have been $419,557. Alternatively, Mr. Addison could have elected to receive a lump sum of $364,634 as of December 31, 2013 and monthly payments of $292 commencing January 1, 2014 for the remainder of his lifetime. In the event Mr. Addison had been eligible to receive benefits and had elected to receive the aforementioned monthly annuity, his designated beneficiary would have received monthly payments of $175 for up to 15 years upon Mr. Addison’s death. If Mr. Addison had died December 31, 2013 before becoming eligible for benefits, his beneficiary would have been entitled to the full lump sum payment of $419,557.

For Mr. Byrne, the lump sum amount would have been $654,179. Alternatively, Mr. Byrne could have elected to receive a lump sum of $494,061 as of December 31, 2013 and monthly payments of $860 commencing January 1, 2014 for the remainder of his lifetime. In the event Mr. Byrne had been eligible to receive benefits and had elected to receive the aforementioned monthly annuity, his designated beneficiary would have received monthly payments of $516 for up to 15 years upon Mr. Byrne’s death. If Mr. Byrne had died December 31, 2013 before becoming eligible for benefits, his beneficiary would have been entitled to the full lump sum payment of $654,179.

For Mr. Bullwinkel, the lump sum amount would have been $1,310,265. Alternatively, Mr. Bullwinkel could have elected to receive a lump sum of $492,561 as of December 31, 2013 and monthly payments of $5,403 commencing January 1, 2014 for the remainder of his lifetime. In the event Mr. Bullwinkel had been eligible to receive benefits and had elected to receive the aforementioned monthly annuity, his designated beneficiary would have received monthly payments of $3,242 for up to 15 years upon Mr. Bullwinkel’s death. If Mr. Bullwinkel had died December 31, 2013 before becoming eligible for benefits, his beneficiary would have been entitled to the full lump sum payment of $1,310,265.

For Mr. Lindsay, the lump sum amount would have been $129,140. Mr. Lindsay was not eligible for the alternative election providing for a reduced lump sum and lifetime monthly payments. If Mr. Lindsay had died December 31, 2013 before becoming eligible for benefits, his beneficiary would have been entitled to the full lump sum payment of $129,140.

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Executive Deferred Compensation Plan

The EDCP is described in the narrative following the 2013 Nonqualified Deferred Compensation table on page 43. As discussed in that section, amounts deferred under the EDCP are required to be paid, or begin to be paid, as soon as practicable following the earliest of a participant’s death, termination of employment, or with respect to pre-2005 deferrals and hypothetical earnings thereon, disability. All amounts payable at a date certain prior to termination of employment, death, or, with respect to pre-2005 deferrals and hypothetical earnings thereon, disability, must be paid in the form of a single cash payment. Payments made after termination of employment, death, or, with respect to pre-2005 deferrals and hypothetical earnings thereon, disability, will also be paid in the form of a single cash payment. Instead of a single cash payment, a participant may, however, elect to have all amounts payable as a result of termination of employment after attainment of age 55, death while employed and after attainment of age 55, or, with respect to pre-2005 deferrals and hypothetical earnings thereon, termination of employment due to disability, paid in the form of annual installments over a period not to exceed five years with respect to post-2004 deferrals and hypothetical earnings thereon or 15 years with respect to pre-2005 deferrals and hypothetical earnings thereon. All amounts credited to a participant’s ledger account continue to be hypothetically invested among the investment alternatives until such amounts are paid in full to the participant or his or her beneficiary.

The “Aggregate Balance at Last FYE” column of the 2013 Nonqualified Deferred Compensation table on page 43 shows the amounts that would have been payable under the EDCP to each of our Named Executive Officers, as of December 31, 2013, (i) with respect to amounts payable at a date certain prior to termination of employment, death, or, as to pre-2005 deferrals and hypothetical earnings thereon, disability, and (ii) with respect to amounts payable after termination of employment, death, or, as to pre-2005 deferrals and hypothetical earnings thereon, disability, if they had been paid using the single sum form of payment. If the Named Executive Officers instead chose payment of the deferrals in annual installments, the annual installment payments over the payment periods selected by the Named Executive Officers are estimated as set forth below: Mr. Marsh — $382,312; Mr. Addison — $147,433; Mr. Byrne — $236,670; Mr. Bullwinkel — $506,220; and Mr. Lindsay — $224,278.

Discussion of Plans are Summaries Only

The discussions of our various compensation plans in this “Executive Compensation” section of the Proxy Statement are merely summaries of the Plans and do not create any rights under any of the Plans and are qualified in their entirety by reference to the Plans themselves.

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DIRECTOR COMPENSATION

Board Fees

Our Board reviews director compensation every year with guidance from the Nominating and Governance Committee. In making its recommendations, the Committee is required by our Governance Principles to consider that compensation should fairly pay directors for work required in a company of our size and scope, compensation should align directors’ interests with the long-term interests of shareholders, and the compensation structure should be transparent and easy for shareholders to understand. We also consider the risks inherent in board service. Approximately every other year, the Nominating and Governance Committee considers relevant publicly available data in making compensation recommendations. The Committee may also consider recommendations from our Chairman and Chief Executive Officer. Officers who are also directors do not receive additional compensation for their service as directors.

In 2013 we provided the following compensation for non-employee directors:

• $170,000 in annual fees, consisting of a $102,000 stock retainer which is paid in shares of our common stock and a $68,000 cash retainer. The stock retainer and the cash retainer are payable on a quarterly basis.

• Committee Chair and Lead Director annual leadership retainer fees, payable in cash, in the following additional amounts: Lead Director — $18,000, Audit Committee Chair — $14,000, Compensation Committee Chair — $8,000, Nominating and Governance Committee Chair — $8,000, Nuclear Oversight Committee Chair — $8,000. A director may only earn one annual leadership retainer fee in the form of either a Committee Chair retainer fee or the Lead Director retainer fee. Such additional Committee Chair and Lead Director retainer fees are also payable on a quarterly basis.

Effective January 1, 2013, all director compensation will be pro-rated for any year of partial service. The annual stock retainer and all fees payable in cash may be deferred at the director’s election pursuant to the terms of the Director Compensation and Deferral Plan discussed below.

Director Compensation and Deferral Plan

Since January 1, 2001, non-employee director compensation and related deferrals have been governed by the SCANA Director Compensation and Deferral Plan. Amounts deferred by directors in previous years under the SCANA Voluntary Deferral Plan continue to be governed by that plan.

Under the Director Compensation and Deferral Plan, instead of receiving quarterly payments of the stock retainer, a director may make an annual irrevocable election to defer all or a portion of the stock retainer into an investment in our common stock, with distribution from the plan to be ultimately payable in shares of our common stock. A director also may elect to defer all or a portion of all other fees into an investment in our common stock or into a growth increment ledger which is credited with growth increments based on the prime interest rate charged from time to time by Wells Fargo Bank, N.A., as determined by us, with distribution from the Plan to be ultimately payable in cash or stock as the Plan may dictate. Amounts payable in our common stock accrue earnings during the deferral period at our dividend rate. All dividends attributable to shares of our common stock credited to each director’s stock ledger account will be converted to additional credited shares of our common stock as though reinvested as of the next business day after the dividend is paid. Directors do not have voting rights with respect to shares credited to their accounts under the Plan. A director’s growth increment ledger will be credited on the first day of each calendar quarter, with a growth increment computed on the average balance in the director’s growth increment ledger during the preceding calendar quarter. The growth increment will be equal to the amount in the director’s growth increment ledger multiplied by the average interest rate we select during the preceding calendar quarter times a fraction the numerator of which is the number of days during such quarter and the denominator of which is 365. Growth increments will continue to be credited until all of a director’s benefits have been paid out of the Plan.

We establish a ledger account for each director that reflects the amounts deferred on his or her behalf and the deemed investment of such amounts into a stock ledger account or a growth investment ledger account. Each ledger account will separately reflect the pre-2005 and post-2004 deferrals and earnings thereon, and the portion of the post-2004 deferrals and earnings thereon payable at a date certain and the portion payable when the director separates from service from the Board. In this discussion, we refer to pre-2005 deferrals as the “pre-2005 ledger account” and to post-2004 deferrals as the “post-2004 ledger account.”

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Directors may elect for payment of any post-2004 deferrals to be until the earlier of separation from service from the Board for any reason or a date certain, subject to any limitations we may choose to apply at the time of election. If a participant does not make a payment election with respect to amounts deferred for any deferral period, such deferrals will be paid in a lump sum payment as soon as practicable after the director’s separation from service from the Board.

Subject to the acceleration provisions of the Plan and Board approval with respect to pre-2005 deferrals, a director may elect an additional deferral period of at least 60 months with respect to any previously deferred amount credited to his or her post-2004 ledger account that is payable at a date certain, and an additional deferral period of at least 12 months for each separate deferral credited to his or her pre-2005 ledger account. With respect to amounts deferred until separation from service from the Board, directors may also elect a new manner of payment with respect to any previously deferred amounts, provided that, in the case of amounts credited to post-2004 ledger accounts that are payable on separation from service from the Board, payments are delayed for 60 months from the date payments would otherwise have commenced absent the election. Directors had the opportunity to elect at any time prior to January 1, 2009 to change the deferral period (accelerate or defer) and/or method of payment with respect to any post-2004 ledger account that was not scheduled for payment in 2008, provided such change did not cause any amounts to be paid in 2008 or cause any amounts otherwise payable in 2008 to be deferred to a later year.

Amounts credited to directors’ post-2004 ledger accounts that are scheduled to be paid at a date certain will be paid in the form of a single sum payment as soon as practicable after the date certain. With respect to amounts credited to pre-2005 ledger accounts, and amounts credited to post-2004 ledger accounts that are scheduled to be paid on separation from service from the Board, directors must irrevocably elect (subject to certain permitted changes) to have payment made in accordance with one of the following distribution forms:

• a single sum payment;

• a designated number of installments payable monthly, quarterly or annually, as elected (and in the absence of an election, annually), over a specified period not in excess of 20 years; or

• in the case of a post-2004 ledger account, payments in the form of annual installments with the first installment being a single sum payment of 10% of the post-2004 ledger account determined immediately prior to the date such payment is made and with the balance of the post-2004 ledger account being paid in annual installments over a total specified period not in excess of 20 years.

Such payments will be paid or commence to be paid as soon as practicable after the conclusion of the deferral period elected.

Notwithstanding any payment election made by a director:

• payments will be paid, or begin to be paid, as soon as practicable following the director’s separation from service from the Board for any reason except as otherwise provided below;

• if a director dies prior to the payment of all or a portion of the amounts credited to his ledger account, the balance of any amount payable will be paid in a cash lump sum to his designated beneficiaries;

• if a director ceases to be a non-employee director but thereafter becomes our employee, all pre-2005 ledger accounts will be paid as soon as practicable after he or she becomes our employee in a single lump sum payment and all post-2004 ledger accounts will be paid as soon as practicable after he or she has incurred a separation from service as a nonemployee director (as determined in accordance with Internal Revenue Code Section 409A);

• if a director’s post-2004 ledger account balance is less than $100,000 ($5,000 for pre-2005 ledger accounts) at the time for payment specified, such amount will be paid in a single payment; and

• in the case of any post-2004 ledger accounts that are payable on separation from service from the Board and that are subject to an additional deferral period of 60 months as a result of the modification of the manner of payment, no payment attributable to any post-2004 ledger accounts will be accelerated to a date earlier than the expiration of the 60 month period.

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We, at our sole discretion, may alter the timing or manner of payment of deferred amounts if the director establishes, to our satisfaction, an unanticipated and severe financial hardship that is caused by an event beyond the director’s control. In such event, we may:

• provide that all, or a portion of, the amount previously deferred by the director immediately be paid in a lump sum cash payment;

• provide that all, or a portion of, the installments payable over a period of time immediately be paid in a lump sum cash payment; or

• provide for such other installment payment schedules as we deem appropriate under the circumstances.

For pre-2005 ledger accounts, severe financial hardship will be deemed to have occurred in the event of the director’s or a dependent’s sudden, lengthy and serious illness as to which considerable medical expenses are not covered by insurance or relative to which there results a significant loss of family income, or other unanticipated events of similar magnitude. For post-2004 ledger accounts, severe financial hardship will be deemed to have occurred from a sudden or unexpected illness or accident of the director or the director’s spouse, beneficiary or dependent, loss of the director’s property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the director’s control.

During 2013, Ms. Miller and Messrs. Micali, Roquemore and Sloan elected to defer 100% of their compensation and earnings and Messrs. Bennett, Hagood and Stowe deferred a portion of their earnings under the Director Compensation and Deferral Plan.

Endowment Plan

In July 2013, the Board closed the SCANA Director Endowment Plan to new participants effective January 1, 2013 after considering management’s recommendation that such a plan may not be perceived as a best corporate governance practice. However, for those participants who remain in the Plan, upon election to their second term, those directors became eligible to participate in the SCANA Director Endowment Plan, which provides for us to make tax deductible, charitable contributions totaling $500,000 to institutions of higher education designated by the director. The Plan was intended to reinforce our commitment to quality higher education and to enhance our ability to attract and retain qualified Board Members. A portion is contributed upon retirement of the director and the remainder upon the director’s death. As of December 31, 2013, the cash obligation under the Plan was $9,900,000 pre-tax and $6,088,500 (assumes 38.5% tax bracket) after-tax. The Plan is funded through insurance policies on the lives of the directors. The 2013 premium for such insurance was $51,485. Currently the premium estimate for 2014 is $34,835.

Designated institutions of higher education in South Carolina, North Carolina and Georgia must be approved by our Chief Executive Officer. Institutions in other states must be approved by the Compensation Committee. The designated institutions are reviewed on an annual basis by the Chief Executive Officer to assure compliance with the intent of the Plan.

Discussions of Plans are Summaries Only

The discussions of our various plans, including the Director Compensation and Deferral Plan and the Director Endowment Plan, are merely summaries of the plans and do not create any rights under any of the plans, and are qualified in their entirety by reference to the plans themselves.

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2013 DIRECTOR COMPENSATION TABLE

The following table sets forth the compensation we paid to each of our non-employee directors in 2013.

Name (a)	Fees Earned or Paid in Cash ($) (b)		Stock Awards ($)(1) (c)		Option Awards ($) (d)		Non-Equity Incentive Plan Compensation ($) (e)		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) (f)		All Other Compensation ($) (g)		Total  ($)(4) (h)
B. L. Amick(2)	$	39,000	$	45,000		—		—		—		—	$	84,000
J. A. Bennett	$	72,000	$	102,000		—		—		—		—	$	174,000
J. F.A.V. Cecil(3)	$	17,000	$	25,500		—		—		—		—	$	42,500
S. A. Decker(2)	$	30,000	$	45,000		—		—		—		—	$	75,000
D. M. Hagood	$	75,000	$	102,000		—		—		—		—	$	177,000
J. W. Martin, III	$	68,000	$	102,000		—		—		—		—	$	170,000
J. M. Micali	$	68,000	$	102,000		—		—		—		—	$	170,000
L. M. Miller	$	76,000	$	102,000		—		—		—		—	$	178,000
J. W. Roquemore	$	68,000	$	102,000		—		—		—		—	$	170,000
M. K. Sloan	$	76,000	$	102,000		—		—		—		—	$	178,000
H. C. Stowe	$	84,000	$	102,000		—		—		—		—	$	186,000
A. Trujillo(3)	$	17,000	$	25,500		—		—		—		—	$	42,500

(1) The stock retainer of $102,000 is required to be paid in our common stock. Shares were issued on January 4, 2013, at a weighted average purchase price of $46.7150, April 1, 2013, at a weighted average purchase price of $50.7400, July 9, 2013, at a weighted average purchase price of $50.1100, and on October 1, 2013, at a weighted average purchase price of $46.0100.

(2) Mr. Amick and Mrs. Decker no longer served on the Board of Directors following the 2013 Annual Meeting held on April 25, 2013.

(3) Mr. Cecil and Mr. Trujillo were elected to the Board of Directors on October 10, 2013.

(4) Fees in excess of $170,000 represent quarterly leadership fees for directors holding a Committee Chair or Lead Director position.

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AUDIT COMMITTEE REPORT

In connection with the December 31, 2013 financial statements, the Audit Committee (i) reviewed and discussed the audited financial statements with management; (ii) discussed with the independent public accountants those matters required to be discussed by Auditing Standard No. 16, as adopted by the Public Company Accounting Oversight Board; (iii) received the written disclosures and the letter from the independent accountants required by applicable requirements of the Public Company Accounting Oversight Board regarding the independent accountant’s communications with the Audit Committee concerning independence; and (iv) discussed with the independent accountant the independent accountant’s independence. Based upon these reviews and discussions, the Audit Committee recommended to the Board of Directors that the audited financial statements be included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 for filing with the Securities and Exchange Commission.

Mr. D. Maybank Hagood (Chairman)

Mr. James M. Micali

Mr. Maceo K. Sloan

Mr. Harold C. Stowe

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PROPOSAL 2 — APPROVAL OF THE APPOINTMENT OF THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Deloitte & Touche LLP served as our independent registered public accounting firm for the year ended December 31, 2013, and the Audit Committee has appointed Deloitte & Touche LLP to serve as our independent registered public accounting firm to audit our 2014 financial statements. Shareholders are being asked to approve this appointment at the 2014 Annual Meeting.

The Board of Directors unanimously recommends a vote FOR approval of Deloitte & Touche LLP’s 2014 appointment.

Unless you indicate to the contrary, the persons identified as proxies on the accompanying proxy card intend to vote the shares represented by your proxy to approve the appointment of Deloitte & Touche LLP as the independent registered public accounting firm to audit our 2014 financial statements.

Representatives of Deloitte & Touche LLP are expected to be present at the 2014 Annual Meeting and available to make such statements as they may desire and to respond to appropriate questions from shareholders.

Pre-Approval of Auditing Services and Permitted Non-Audit Services

Our 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 public 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 for approval at its next scheduled meeting.

Independent Registered Public Accounting Firm’s Fees

The following table sets forth the aggregate fees billed to SCANA and its subsidiaries for the fiscal years ended December 31, 2013 and 2012 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu and their respective affiliates.

	2013		2012
Audit Fees(1)	$	2,605,000	$	2,432,500
Audit Related Fees(2)	$	140,459	$	283,104
Tax Fees		—		—
All Other Fees		—		—
Total Fees	$	2,745,459	$	2,715,604

(1) Fees for Audit Services billed for 2013 and 2012 consisted of audits of annual financial statements, comfort letters, statutory and regulatory audits, consents and other services related to Securities and Exchange Commission filings, and accounting research.

(2) Fees primarily for employee benefit plan audits and, in 2012, for non-statutory audit services.

In 2013 and 2012, all of the Audit Fees and Audit Related Fees were approved by the Audit Committee.

THE BOARD OF DIRECTORS UNANIMOUSLY RECOMMENDS A VOTE “FOR” APPROVAL OF DELOITTE & TOUCHE LLP’s 2014 APPOINTMENT.

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PROPOSAL 3 — APPROVAL OF BOARD-PROPOSED AMENDMENTS TO ARTICLE 8 OF OUR ARTICLES OF INCORPORATION TO DECLASSIFY THE BOARD OF DIRECTORS AND PROVIDE FOR THE ANNUAL ELECTION OF ALL DIRECTORS

Background of the Proposal

Our Articles of Incorporation currently provide for a classified Board of Directors divided into three classes, with each class being elected for a three-year term. In 2012 and 2013, we received shareholder proposals recommending the declassification of our Board of Directors. In 2012, 38% of our outstanding shares voted in favor of the proposal, and in 2013, 47% of our outstanding shares voted in favor of the proposal. We also received a shareholder proposal for our 2014 Annual Meeting seeking a shareholder vote on declassification. In light of the apparent growing shareholder support for declassification, the Board has proposed amendments to our Articles of Incorporation to effect declassification, and, is recommending that our shareholders approve such amendments at the 2014 Annual Meeting. Based on our agreement to submit a Board proposal on declassification to shareholders, the shareholder proposal for the 2014 Annual Meeting was withdrawn.

Our Board is committed to strong corporate governance practices. In considering the 2012, 2013 and 2014 shareholder proposals, as well as the growing support of institutional investor groups for annual election of directors, the Board took into account the advantages and disadvantages of a classified Board. In favor of retaining the classified board structure, the Board noted that: a classified board structure provides valuable stability and continuity of leadership; a classified board structure enables us to recruit high quality directors who are willing to invest the time and energy necessary to understand our business, technology, competitive environment and strategic goals; and a classified board structure helps protect shareholder value in case of an unsolicited takeover proposal at an unfair price. In favor of declassification, the Board noted that declassification would allow our shareholders to evaluate all directors annually and would be consistent with the developing view that a declassified board is a corporate governance best practice. The Board also considered that many U.S. public companies have eliminated their classified board structures in recent years based on the perception of a growing number of investors that annual election of directors is the primary means for shareholders to influence corporate governance policies and to increase board accountability.

After carefully reviewing these various considerations, the Board decided to propose amendments to Article 8 of our Articles of Incorporation to declassify the Board and provide for annual election of all directors, and to recommend that our shareholders vote in favor of the amendments.

Proposed Amendments to Article 8 of the Articles of Incorporation

Under the proposed amendments, the annual election of directors would be phased in gradually to assure a smooth transition. If the amendments are adopted, they would become effective upon our filing of articles of amendment with the South Carolina Secretary of State following the 2014 Annual Meeting. Accordingly, directors elected at the 2015 annual meeting and thereafter would be elected to one-year terms. Consistent with our Articles of Incorporation as in effect for the 2014 Annual Meeting, directors to be elected at the 2014 Annual Meeting will be elected to serve three-year terms, expiring at the 2017 annual meeting. Directors elected at the 2013 annual meeting will continue to serve their current terms until the 2016 annual meeting, and directors elected at the 2012 annual meeting will continue to serve their current terms until the 2015 annual meeting. Article 8 of our Articles of Incorporation would also be amended to delete other references to classification of the Board and to provide that a director elected to fill a newly created directorship or vacancy would serve until the next annual meeting of shareholders.

If the proposed amendments to Article 8 of our Articles of Incorporation are not adopted by shareholders, the Board of Directors will remain classified.

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Text of the Proposed Amendments

The text of the proposed amendments to our Articles of Incorporation are as follows:

8.A. The number of directors of the corporation that shall constitute the entire Board of Directors shall be fixed from time to time by or pursuant to the provisions of the By-laws of the corporation. Any such provision shall continue in effect unless and until changed by the Board of Directors, but no such changes shall affect the term of any director then in office. Upon the adoption of this Section 8.A., Directors elected prior to the 2015 annual meeting of shareholders shall continue to be, and are, divided into three classes (I, II and III), as nearly equal in number as possible, and shall hold office for a term expiring at the annual meeting of shareholders held in the third year following the year of their respective elections and until their respective successors are elected and qualified. Directors elected at each annual meeting of shareholders commencing with the annual meeting of shareholders in 2015 shall hold office for a term of one year expiring at the next annual meeting of shareholders and until their respective successors are duly elected and qualified. No person who is not a salaried employee of the corporation who would attain the age of 70 or older during his term of service as a director shall be eligible to be elected a director. No person who is a salaried employee of the corporation who is age 65 or older shall be eligible to be elected a director, and the term of office any director who is a salaried employee of the corporation shall expire upon such director attaining the age of 65 or upon retirement from active service with the corporation, whichever is earlier; provided, however, a person who is the Chief Executive Officer shall be eligible for election as a director even if such person is age 65 or older or has retired from active service with the corporation, and such person’s term shall not expire as a result of attaining age 65 or prior retirement from active service with the corporation.

B. Newly created directorships resulting from any increase in the authorized number of directors or any vacancies in the Board of Directors resulting from death, resignation, retirement, disqualification, removal from office or any other cause shall be filled only by the Board of Directors then in office, although less than a quorum. Directors elected to fill a newly created directorship or other vacancies shall hold office until the next annual meeting of shareholders and until such director’s successor has been elected and has qualified.

C. No changes to Article 8.C.

D. Notwithstanding the foregoing, if at any time the holders of any one or more classes or series of preferred stock issued by the corporation shall have the right, voting separately by class or series, to elect directors at an annual or special meeting of stockholders, the election, term of office, filling of vacancies and other features of such directorships shall be governed by the terms of these Restated Articles of Incorporation applicable thereto.

Required Vote and Board Recommendation

Our Articles of Incorporation require that, to be adopted, the proposed amendments must be approved by the affirmative vote of at least 80% of all outstanding shares of our common stock. If approved, the amendments will become effective upon filing of articles of amendment with the Secretary of State of South Carolina.

THE BOARD OF DIRECTORS RECOMMENDS A VOTE “FOR” APPROVAL OF THE AMENDMENTS TO ARTICLE 8 OF OUR ARTICLES OF INCORPORATION TO DECLASSIFY THE BOARD OF DIRECTORS AND PROVIDE FOR THE ANNUAL ELECTION OF ALL DIRECTORS.

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PROPOSAL 4 — ADVISORY (NON-BINDING) VOTE TO APPROVE EXECUTIVE COMPENSATION

In 2010, Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which, among other things, imposed a number of new corporate governance requirements on publicly held companies. Section 14A of the Securities Exchange Act of 1934 (the “1934 Act”) adopted under the Dodd-Frank Act requires that, at least every three years at the annual meeting of shareholders, we must submit a separate resolution subject to a non-binding shareholder advisory vote to approve the compensation of our Named Executive Officers as disclosed in this Proxy Statement pursuant to Item 402 of Regulation S-K under the 1934 Act.

This proposal gives you as a shareholder the opportunity to vote for, against, or abstain from voting, on the following resolution:

“RESOLVED, that the compensation paid to the Company’s Named Executive Officers, as disclosed pursuant to Item 402 of Regulation S-K, including the ‘Compensation Discussion and Analysis,’ compensation tables and narrative discussion is hereby APPROVED.”

Because your vote is advisory, it will not be binding on our Board and may not be construed as overruling any decision by the Board, nor to create or imply any additional fiduciary duty of the Board. However, the Board will review the voting results, and may, as it did with respect to the results of the vote in 2011, in its sole discretion, take into account the outcome of the vote when considering future executive compensation arrangements.

Shareholders are encouraged to review carefully the “Executive Compensation” section of this Proxy Statement for a detailed discussion of our executive compensation program.

Board of Directors’ Recommendation

Our overall executive compensation policies and procedures are described in the “Executive Compensation” section, including the tabular disclosure regarding Named Executive Officer compensation (together with the accompanying narrative disclosure) in this Proxy Statement. Our compensation policies and procedures are centered on a pay-for-performance approach that links total rewards to achievement of corporate business unit and individual goals, and are designed to be aligned with the long-term interests of our shareholders, as described in the “Executive Compensation” section. As previously discussed, we have designed our compensation program to reward senior executive officers for their individual and collective performance and for our collective performance in achieving target goals for earnings per share and total shareholder return and other annual and long-term business objectives. We believe our program performs a vital role in keeping executives focused on improving our performance and enhancing shareholder value while rewarding successful individual executive performance in a way that helps to assure retention.

The Compensation Committee, which is comprised entirely of independent directors, oversees our executive compensation program and continually monitors our policies to ensure that they continue to emphasize programs that reward executives for results that are consistent with shareholder interests.

Our Board and our Compensation Committee believe that our commitment to responsible compensation practices justifies a vote by shareholders for the resolution approving the compensation of our executives as disclosed in this Proxy Statement.

THE BOARD OF DIRECTORS UNANIMOUSLY RECOMMENDS A VOTE “FOR” APPROVAL OF THE COMPENSATION OF OUR NAMED EXECUTIVE OFFICERS.

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OTHER INFORMATION

Section 16(a) Beneficial Ownership Reporting Compliance

The rules of the Securities and Exchange Commission require that we disclose late filings of reports of beneficial ownership and changes in beneficial ownership of our common stock by our directors, executive officers and greater than 10% beneficial owners. To our knowledge, based solely on a review of Forms 3, 4 and 5 and amendments to such forms furnished to us and written representations made to us, all filings on behalf of such persons were made on a timely basis in 2013.

Shareholder Proposals and Nominations

In order to be considered for inclusion in our Proxy Statement and Proxy Card for the 2015 Annual Meeting of Shareholders, a shareholder proposal must be received by us at SCANA Corporation, c/o Corporate Secretary, 220 Operation Way, Mail Code D133, Cayce, South Carolina 29033, no later than November 24, 2014. Securities and Exchange Commission rules contain standards for determining whether a shareholder proposal is required to be included in a proxy statement.

Under our bylaws, any shareholder who intends to present a proposal or nominate an individual to serve as a director at the 2015 Annual Meeting must notify us no later than November 24, 2014 of the intention to present the proposal or make the nomination. The shareholder also must comply with the other requirements in the bylaws. Any shareholder may request a copy of the relevant bylaw provision by writing to the Office of the Corporate Secretary, SCANA Corporation, 220 Operation Way, Mail Code D133, Cayce, South Carolina 29033.

Expenses of Solicitation

This solicitation of proxies is being made by our Board of Directors. We pay the cost of preparing, assembling and mailing this proxy soliciting material, including certain expenses of brokers and nominees who mail proxy material to their customers or principals. We have retained Georgeson, Inc., 480 Washington Boulevard, Jersey City, NJ 07310, to assist in the solicitation of proxies for the 2014 Annual Meeting and to provide ongoing governance advice and consultation at a fee of $18,000 plus associated costs and expenses.

In addition to the use of the mail, proxies may be solicited personally, by telephone, by email or other electronic means by our officers and employees without additional compensation.

View Proxy Statement and Annual Report Information through the Internet

IMPORTANT NOTICE REGARDING AVAILABILITY OF PROXY MATERIALS FOR

SHAREHOLDER MEETING TO BE HELD ON APRIL 24, 2014:

The Proxy Statement, Notice of 2014 Annual Meeting, Annual Financial Statements, and Management’s Discussion and Analysis and Related Annual Report Information are available through the Internet at www.scana.com under the caption “Investor Relations — Financial Reports — Proxy Statements.”

SCANA shareholders may view proxy statements and annual report information at this website. If you choose to view proxy materials through the Internet, you may incur costs, such as telephone and Internet access charges, for which you will be responsible.

62

Availability of Form 10-K

We have filed with the Securities and Exchange Commission our Annual Report on Form 10-K for the fiscal year ended December 31, 2013. A copy of the Form 10-K, including the financial statements and financial statement schedules and a list of exhibits, will be provided without charge to each shareholder to whom this proxy statement is delivered upon our receipt of a written request from such shareholder. The exhibits to the Form 10-K also will be provided upon request and payment of copying charges. Requests for a copy of the Form 10-K should be directed to:

Byron W. Hinson

Director-Investor Relations

SCANA Corporation

220 Operation Way, Mail Code B124

Cayce, South Carolina 29033

Incorporation by Reference

We file various documents with the Securities and Exchange Commission, some of which incorporate information by reference. This means that information we have previously filed with the Securities and Exchange Commission should be considered as part of the filing.

Neither the Compensation Committee Report nor the Audit Committee Report shall be deemed to be filed with the Securities and Exchange Commission or incorporated by reference into any of our filings under the Securities Exchange Act of 1934 or the Securities Act of 1933, unless specifically incorporated by reference therein.

References to Our Website Address

References to our website address throughout this Proxy Statement and the accompanying materials are for informational purposes only, or to fulfill specific disclosure requirements of the Securities and Exchange Commission’s rules or the New York Stock Exchange Listing Standards. These references are not intended to, and do not, incorporate the contents of our website by reference into this Proxy Statement or the accompanying materials.

Directions to the Annual Meeting

From Charlotte:

• Take I-77 South to Exit 9-A (Garners Ferry Road).

• Follow the exit onto Garners Ferry Road under I-77. East Exchange Place is the first right turn off Garners Ferry Road immediately before Quality Inn & Suites.

• Follow to Leaside at the end of East Exchange Place. The parking lot is located in front of the building.

From Charleston:

• Take I-26 to I-77 North toward Charlotte.

• Take Exit 9-A and turn right at traffic light onto Garners Ferry Road. East Exchange Place is the first right turn off Garners Ferry Road immediately before Quality Inn & Suites.

• Follow to Leaside at the end of East Exchange Place. The parking lot is located in front of the building.

From Greenville:

• Take I-26 East toward Columbia/Charleston.

• Take Exit 116 onto I-77 North toward Charlotte.

• Take Exit 9-A and turn right at traffic light onto Garners Ferry Road. East Exchange Place is the first right turn off Garners Ferry Road immediately before Quality Inn & Suites.

• Follow to Leaside at the end of East Exchange Place. The parking lot is located in front of the building.

63

From Downtown (Columbia):

• Take US 378/76 East (Devine Street/Garners Ferry Road) past the Veterans Administration Hospital (also known as Dorn VA Medical Center) and under the I-77 overpass. East Exchange Place is the first right turn off Garners Ferry Road immediately before Quality Inn & Suites.

• Follow to Leaside at the end of East Exchange Place. The parking lot is located in front of the building.

Tickets to the Annual Meeting

An admission ticket or proof of share ownership as of the record date, March 4, 2014, is required to attend the 2014 Annual Meeting. If you plan to use the admission ticket, please remember to detach it from your proxy card before mailing your proxy card. If you forget to bring the admission ticket, you will be admitted to the meeting only if you are listed as a shareholder of record as of the close of business on March 4, 2014 and bring proof of identification. If you hold your shares through a stockbroker or other nominee, you must provide proof of ownership by bringing either a copy of the voting instruction card provided by your broker or a brokerage statement showing your share ownership as of March 4, 2014.

If you are a shareholder of record and your shares are owned jointly and you need an additional ticket, you should contact the Corporate Secretary, SCANA Corporation, 220 Operation Way, Mail Code D133, Cayce, South Carolina 29033, or call 803-217-7568.

SCANA CORPORATION

Gina Champion

Corporate Secretary

March 24, 2014

64

FINANCIAL APPENDIX

Index to Annual Financial Statements, Management’s Discussion and Analysis and Related Annual Report Information:

Cautionary Statement Regarding Forward-Looking Information	F-2
Definitions	F-4
Selected Financial and Other Statistical Data	F-6
SCANA’s Business	F-7
Management’s Discussion and Analysis of Financial Condition and Results of Operations	F-8
Quantitative and Qualitative Disclosures About Market Risk	F-31
Report of Independent Registered Public Accounting Firm	F-33
Consolidated Balance Sheets	F-34
Consolidated Statements of Income	F-36
Consolidated Statements of Comprehensive Income	F-37
Consolidated Statements of Cash Flows	F-38
Consolidated Statements of Changes in Common Equity	F-39
Notes to Consolidated Financial Statements	F-40
Management Report on Internal Control Over Financial Reporting	F-76
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting	F-77
Market for Common Equity and Related Stockholder Matters	F-78
Performance Graph	F-79
Executive Officers of SCANA Corporation	F-80

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

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

(3) current and future litigation;

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

(5) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial markets;

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

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

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

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

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

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

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

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

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

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

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

(17) the availability of fuels such as coal, natural gas and enriched uranium used to produce electricity; the availability of purchased power and natural gas for distribution; the level and volatility of future market prices for such fuels and purchased power; and the ability to recover the costs for such fuels and purchased power;

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

(19) labor disputes;

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

F-2

(21) changes in taxes;

(22) inflation or deflation;

(23) compliance with regulations;

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

(25) the other risks and uncertainties described from time to time in the periodic reports filed by SCANA or its subsidiaries with the SEC.

SCANA disclaims any obligation to update any forward-looking statements.

F-3

DEFINITIONS

Abbreviations used in this Financial Appendix have the meanings set forth below unless the context requires otherwise:

TERM	MEANING
AFC	Allowance for Funds Used During Construction
ANI	American Nuclear Insurers
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement Obligation
BACT	Best Available Control Technology
BLRA	Base Load Review Act
CAA	Clean Air Act, as amended
CAIR	Clean Air Interstate Rule
CCR	Coal Combustion Residuals
CEO	Chief Executive Officer
CFO	Chief Financial Officer
CFTC	Commodity Futures Trading Commission
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act
CGT	Carolina Gas Transmission Corporation
COL	Combined Construction and Operating License
Company	SCANA, together with its consolidated subsidiaries
Consortium	A consortium consisting of Westinghouse and Stone and Webster, Inc., a subsidiary of 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
DOT	United States Department of Transportation
DSM Programs	Demand Side Management Programs
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
Fuel Company	South Carolina Fuel Company, Inc.
GENCO	South Carolina Generating Company, Inc.
GHG	Greenhouse Gas
GPSC	Georgia Public Service Commission
GWh	Gigawatt hour
IRP	Integrated Resource Plan
IRS	United States Internal Revenue Service
JEDA	South Carolina Jobs-Economic Development Authority
kWh	Kilowatt-hour
Level 1	A fair value measurement using unadjusted quoted prices in active markets for identical assets or liabilities
Level 2	A fair value measurement using observable inputs other than those for Level 1, including quoted prices for similar (not identical) assets or liabilities or inputs that are derived from observable market data by correlation or other means

F-4

TERM	MEANING
Level 3	A fair value measurement using unobservable inputs, including situations where there is little, if any, market activity for the asset or liability
LOC	Lines of Credit
LTECP	SCANA Long-Term Equity Compensation Plan
MGP	Manufactured Gas Plant
MMBTU	Million British Thermal Units
MW	Megawatt
NASDAQ	The NASDAQ Stock Market, Inc.
NCUC	North Carolina Utilities Commission
NEIL	Nuclear Electric Insurance Limited
New Units	Nuclear Units 2 and 3 under construction at Summer Station
NPDES	National Permit Discharge Elimination System
NRC	United States Nuclear Regulatory Commission
NSPS	New Source Performance Standards
NSR	New 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
PHMSA	United States Pipeline Hazardous Materials Safety Administration
Price-Anderson	Price-Anderson Indemnification Act
PRP	Potentially Responsible Party
PSNC Energy	Public Service Company of North Carolina, Incorporated
RCC	Replacement Capital Covenant
RSA	Natural Gas Rate Stabilization Act
Santee Cooper	South Carolina Public Service Authority
SCANA	SCANA Corporation, the parent company
SCANA Energy	A division of SEMI which markets natural gas in Georgia
SCE&G	South Carolina Electric & Gas Company
SCEUC	South Carolina Energy Users Committee
SCI	SCANA Communications, Inc.
SCPSC	Public Service Commission of South Carolina
SEC	United States Securities and Exchange Commission
SEMI	SCANA Energy Marketing, Inc.
Southern Natural	Southern Natural Gas Company
Summer Station	V. C. Summer Nuclear Station
Transco	Transcontinental Gas Pipeline Corporation
TSR	Total Shareholder Return
Westinghouse	Westinghouse Electric Company LLC
Williams Station	A.M. Williams Generating Station, owned by GENCO
WNA	Weather Normalization Adjustment

F-5

SELECTED FINANCIAL AND OTHER STATISTICAL DATA

As of or for the Year Ended December 31,	2013		2012		2011		2010		2009
	(Millions of dollars, except statistics and per share amounts)
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

F-6

SCANA’S BUSINESS

Regulated Utilities

SCE&G is engaged in the generation, transmission, distribution and sale of electricity to approximately 678,000 customers and the purchase, sale and transportation of natural gas to approximately 329,000 customers (each as of December 31, 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 509,000 residential, commercial and industrial customers (as of December 31, 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.

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-related risk management services. SCANA Energy, a division of SEMI, sells natural gas to approximately 454,000 customers (as of December 31, 2013, and includes approximately 68,000 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 was renewed by the GPSC through August 31, 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 1,125 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.

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.

F-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-owned nonregulated subsidiaries provide fiber optic and other telecommunications services and provide service contracts 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 earned by the Company’s regulated and nonregulated businesses (including the holding company) and the percentage of total assets held by them.

	2013		2012		2011
Revenues
Regulated		75%		77%		74%
Nonregulated		25%		23%		26%
Net Income
Regulated		97%		99%		97%
Nonregulated		3%		1%		3%
Assets
Regulated		95%		95%		94%
Nonregulated		5%		5%		6%

F-8

Key Earnings Drivers and Outlook

During 2013, economic growth continued to improve in the southeast. Significant industrial announcements were made in the Company’s South Carolina and North Carolina service territories during the 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. Residential and commercial customer growth rates in the Company’s regulated businesses also remained positive. Unemployment rates for the states in which the Company primarily provides service also improved in 2013, though such rates improved in part due to people leaving the workforce. Nationwide, the 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, 2012		7.8	%		8.7	%		9.4	%		8.6	%
December 31, 2011		8.9	%		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, 2013, SCE&G provided electricity to approximately 678,000 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, provides financing for and sells at cost to SCE&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 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 is constructing two 1,250 MW (1,117 MW, net) nuclear generation units at the site of Summer Station. SCE&G will jointly own the New Units with Santee Cooper, and SCE&G will be responsible for the cost of and receive the output from the New Units in proportion to its share of ownership, with Santee Cooper responsible for and receiving the remaining share. 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 one percent ownership interest in the New Units at the commercial operation date of Unit 2, will

F-9

acquire an additional two percent ownership interest no later than the first anniversary of such commercial operation date, and will acquire 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 to third parties until the New Units are complete.

SCE&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 $5.4 billion for plant and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC. In addition, under the terms of the agreement 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 foundation 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 fourth 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 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 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 and other matters, see New Nuclear Construction Matters herein and Note 2 and Note 10 to the consolidated financial statements.

Environmental

As part of the President’s Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA was directed to issue a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The rule became final on January 8, 2014 and requires all new fossil fuel-fired power plants to meet the carbon dioxide emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants 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.

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The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. New federal effluent limitation guidelines for steam electric generating units were published in the Federal Register on June 7, 2013, and the ELG Rule is expected to be finalized May 22, 2014. The EPA expects compliance as soon as possible after July 2017 but no later than July 2020. Additionally, the EPA is expected to issue a rule that modifies requirements for existing cooling water intake structures in early 2014, and Congress is expected to consider further amendments to the CWA.

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 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 above environmental initiatives and other similar issues are described in Environmental Matters herein and in Note 10 to the consolidated financial statements. Unless otherwise noted, the Company cannot predict when regulatory rules or legislative requirements for any of these initiatives will become final, if at all, or what conditions they may impose on the Company, 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 South Carolina and North Carolina. At December 31, 2013 this segment provided natural gas to approximately 838,000 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 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 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. In addition, the production of shale gas in the United States has resulted in significantly lower prices for this commodity, and such prices are expected to continue for the foreseeable future.

Retail Gas Marketing

SCANA Energy, a division of SEMI, comprises the retail gas marketing segment. This segment markets natural gas to approximately 454,000 customers throughout Georgia (as of December 31, 2013, and includes approximately 68,000 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 . SCANA Energy receives funding from Georgia’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

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was extended by the GPSC through August 31, 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).

SCANA Energy and certain of SCANA’s other natural gas distribution and marketing segments maintain gas inventory and 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

	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

2013 vs 2012	Basic earnings per share 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, dilution from additional shares outstanding and higher interest expense, as further described below.
2012 vs 2011	Basic earnings per share increased due to higher electric and gas margins and gains on sales of communications 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.

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Electric Operations

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

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 2012

Margin 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 2011

Margin 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 2012	Retail 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 2011	Retail 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.

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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 2012

Margin 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 2011

Margin 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.

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 2012	Total sales volumes increased primarily due to customer growth, increased industrial usage and the effects of weather.
2012 vs 2011	Residential 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 2012	Changes in operating revenues and net income are due to higher demand in 2013 primarily as a result of milder weather in 2012.
2012 vs 2011	Reductions 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.

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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 2012	Operating revenues and net income increased due to higher industrial sales volume and higher market prices.
2012 vs 2011	Operating 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

2013 vs 2012

Other 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 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 2011

Other operation and maintenance expenses increased by $9.3 million due to higher generation, transmission and distribution expenses and by $25.0 million due to higher incentive compensation and other benefits. These increases were partially offset by $3.9 million due to lower customer service expenses, including bad debt expense, and 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.

Net Periodic Pension Benefit Cost

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

Millions of dollars	2013		Change		2012		Change		2011
Income Statement Impact:
Employee benefit costs (within other operation and maintenance)	$	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%

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Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts included in rates for its retail electric and gas distribution regulated operations. In connection with the SCPSC’s July 2010 electric rate order and November 2010 natural gas RSA order, SCE&G began deferring, as a regulatory asset, all pension cost related to retail electric and gas operations that otherwise would have been charged to expense. Effective in January 2013, in connection with the December 2012 rate order, SCE&G began amortizing 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 rate rider that may be adjusted annually. Similarly, in connection with the October 2013 RSA order, 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 (see Note 2 to the consolidated financial statements). In 2013, such amortizations totaled approximately $2.0 million for 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%

2013 vs 2012

Changes 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 2011

Changes 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 5.8% of income before income taxes in 2013, 5.4% in 2012 and 3.9% in 2011.

Interest Expense

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

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. Other interest expense decreased in 2013 and 2012, primarily due to reductions in principal balances outstanding on short-term debt over the respective prior year and also decreased due to the reversal in 2012 of interest which had been accrued in 2011 related to a tax uncertainty that was resolved (see Note 5 to the consolidated financial statements).

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Income Taxes

Income tax expense increased in 2013 over 2012 and in 2012 over 2011 primarily due to increases in income before taxes. The increase in the effective tax rate in 2013 is principally attributable to lower recognition of EIZ Credits upon the completion of the amortization of certain such credits in 2012.

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its contractual cash obligations will be met through internally generated funds, the incurrence of additional short- and long-term indebtedness and sales of equity securities. The Company expects that, barring a future impairment of the capital markets, it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future, including the cash requirements for nuclear construction and refinancing maturing long-term debt. The Company’s ratio of earnings to fixed charges for the year ended December 31, 2013 was 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.

The Company 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 $99 million of additional equity during 2013. Due primarily to new nuclear construction plans, the Company anticipates keeping this strategy in place for the foreseeable future. In addition, on March 5, 2013, SCANA settled all forward sales contracts related to its common stock through the issuance of approximately 6.6 million common shares, resulting in net proceeds of approximately $196 million.

SCANA’s leverage ratio of long- and short-term debt to capital was approximately 56% at December 31, 2013. SCANA has publicly announced its desire to maintain its leverage ratio between 54% and 57%, but SCANA’s ability to do so depends on a number of factors. In the future, if SCANA is not able to 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 $1.1 billion in 2013 and are estimated to be $1.7 billion in 2014.

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

Estimated Capital Expenditures

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.

The Company’s contractual cash obligations as of December 31, 2013 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	$	10,954	$	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 currently responsible for 55 percent of the cost and receiving 55 percent of the output, and the other joint owner (or owners) the remaining 45 percent. Also included in the table above is the 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,

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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 for the foreseeable future. Cash payments under the postretirement health care and life insurance benefit plan were $9.2 million in 2013, and such annual payments are expected to be the same or increase up to $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 Quantitative and Qualitative Disclosures About Market Risk. At December 31, 2013, the Company had posted $6.4 million in cash collateral for such contracts. In addition, the Company had posted $20.3 million in cash collateral related 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.

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

GENCO has obtained FERC authority to issue short-term indebtedness not to exceed $150 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2014.

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 were parties to five-year credit agreements in the amounts of $300 million, $1.2 billion, of which $500 million relates to Fuel Company, and $100 million, respectively, which expire in October 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’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. For a list of banks providing credit support and other information, see Note 4 to the consolidated financial statements.

As of December 31, 2013, the Company had no outstanding borrowings under its $1.8 billion credit facilities, had approximately $376 million in commercial paper borrowings outstanding, was obligated under $3.3 million in LOC supported letters of credit, and held approximately $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 2013 were approximately $463 million. Short-term cash needs were met primarily through the issuance of commercial paper.

At December 31, 2013, the Company’s long-term debt portfolio has a weighted average maturity of approximately 18 years and bears an average cost of 5.74%. Substantially all of the Company’s long-term debt bears

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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.

The Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At December 31, 2013, approximately $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 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) which bear interest at 7.70% and mature 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, credit rating agencies consider securities like the Hybrids to be hybrid debt instruments and give some 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” 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 are 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, 2013, the Bond Ratio was 5.28.

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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.

Investing Activities

The Company paid approximately $6 million, net, through the third quarter of 2013 to settle interest rate derivative contracts upon 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, see Note 4 to the consolidated financial statements.

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

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ENVIRONMENTAL MATTERS

The Company’s operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. 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, 2013, the Company’s capital expenditures for environmental control equipment at its fossil fuel generating stations totaled $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, 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, 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 2013, 2012 and 2011 related to SCE&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 $9.5 million for 2014 and $82.5 million for the four-year period 2015-2018. These expenditures are included in the Company’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’s operations advanced during 2013. The Company cannot predict whether such legislation will be introduced or enacted in 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 2013 and more are expected to advance in 2014 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, 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. Other business and financial risks arising from such climate change could also 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, 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.

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In 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide. SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements. On July 6, 2011 the EPA issued the CSAPR. This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states. CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide. On December 30, 2011, the 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 have allowed the Company to comply with the reinstated CAIR and will also allow it to comply with CSAPR, 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 addition, the DOJ, on behalf of the EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by the EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement. Though the Company cannot predict what action, if any, the EPA will initiate against it, any costs incurred are expected to be recoverable through rates.

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’s electric system, as well as impacts on employees and customers and on the Company’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. 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 who 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.

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 facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule was published in the Federal Register on June 7, 2013, and is expected to be finalized May 22, 2014. The EPA expects compliance as soon as possible after July 2017 but no later than July 2020.

Additionally, the EPA is expected to issue a rule that modifies requirements for existing cooling water intake 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. These provisions, if passed, could have a material impact on the financial condition, results of operations and cash flows of the Company. The Company believes that any additional costs imposed by such regulations would be recoverable through rates.

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Hazardous and Solid Wastes

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

Electric Operations

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. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. At December 31, 2013, such regulatory assets totaled approximately $1.2 million. Other environmental costs are recorded to 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 2017 and will cost an additional $20.2 million. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At December 31, 2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $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’s actual remediation costs for these sites will depend on a number of factors,

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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 $2.8 million, the estimated remaining liability at December 31, 2013. PSNC Energy expects to recover through rates any cost allocable to PSNC Energy arising from the remediation of these sites.

REGULATORY MATTERS

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

Company	Regulatory Jurisdiction/Matters
SCANA	The SEC as to the issuance of certain securities and other matters and the FERC as to certain acquisitions and other matters.
SCANA and all subsidiaries	The CFTC to the extent they transact swaps as defined in Dodd-Frank.
SCE&G	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; 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 GENCO	The 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.
GENCO	The 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 Company	The SEC as to the issuance of certain securities.
PSNC Energy	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, and the SEC as to the issuance of certain securities.
SCE&G, PSNC Energy and CGT	The PHMSA and the DOT as to integrity management requirements for gas distribution pipeline systems and natural gas transmission systems, respectively.
CGT	The FERC as to transportation rates, service, accounting and other matters.
SCANA Energy	The 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 Note 2 to the consolidated financial statements. In addition, 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.

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

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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 the Company’s Electric Operations 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 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, 2013, the Company’s net investments in fossil/hydro and nuclear generation assets were approximately $2.4 billion and $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, the effects of different rate schedules 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 $183.1 million at December 31, 2013 and $189.8 million at December 31, 2012, compared to total revenues of $4.5 billion and $4.2 billion for the years 2013 and 2012, respectively.

Nuclear Decommissioning

Accounting for decommissioning costs for nuclear power plants involves significant estimates related to costs to be incurred many years into 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 $696.8 million, stated in 2012 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 for 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.

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 present 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 recognition has no significant impact on results of operations. As of December 31, 2013, the Company has recorded AROs of $191

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million for nuclear plant decommissioning (as discussed above) and AROs of $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.

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 pension 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 expected to further lessen the significance of pension costs and 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.

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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.

NEW NUCLEAR CONSTRUCTION MATTERS

SCE&G is constructing two 1,250 MW (1,117 MW, net) nuclear generation units at the site of Summer Station. SCE&G will jointly own the New Units with Santee Cooper, and SCE&G will be responsible for the cost of and receive the output from the New Units in proportion to its share of ownership, with Santee Cooper responsible for and receiving the remaining share. 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 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 acquire 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 to third parties until the New 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 share of the estimated cash outlays (future value, excluding AFC) for its current 55% ownership share totals approximately $5.4 billion for plant and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC. In addition, under the terms of the agreement 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. 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 revised rates filings under the BLRA.

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

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

F-28

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 to the consolidated financial statements. 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 for 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 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.

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.

F-29

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. Under current provisions of the Internal 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 that it expects to acquire. Additional production tax credits related to the 5% interest could total as much as $125 million.

OTHER MATTERS

Financial Regulatory Reform

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

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 Note 10 to the consolidated financial statements.

F-30

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, 2013 Millions of dollars	Expected Maturity Date
	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 ($)		604.4		654.4		4.4		4.4		4.4		141.8		1,413.8		13.0
Average Pay Interest Rate (%)		3.97		4.17		6.17		6.17		6.17		4.72		4.16		—
Average Receive Interest Rate (%)		0.25		0.25		0.94		0.94		0.94		0.49		0.28		—
December 31, 2012 Millions of dollars	Expected Maturity Date
	2013		2014		2015		2016		2017		Thereafter		Total		Fair Value
Long-Term Debt:
Fixed Rate ($)		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 $3 million at December 31, 2013 and $9 million at December 31, 2012, which amounts do not have a stated interest rate associated with them.

For further discussion of the Company’s long-term debt and interest rate derivatives, see Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources and Notes 4 and 6 to the consolidated financial statements.

F-31

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 MMBTU. Fair value represents quoted market prices.

Expected Maturity:

						Options
	Futures Contracts					Purchased Call		Purchased Put
	Long		Short			(Long)		(Short)
2014					2014
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	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 and PSNC Energy.

PSNC Energy utilizes futures, options and swaps to hedge gas purchasing activities. PSNC Energy’s tariffs 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.

F-32

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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”) as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, cash flows and changes in common equity for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements 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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

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

Charlotte, North Carolina

February 28, 2014

F-33

SCANA Corporation

CONSOLIDATED BALANCE SHEETS

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.

F-34

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.

F-35

SCANA Corporation

CONSOLIDATED STATEMENTS OF INCOME

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.

F-36

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.

F-37

SCANA Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

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.

F-38

SCANA Corporation

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY

	Common Stock				Retained Earnings			Accumulated Other Comprehensive Loss			Total
Millions	Shares		Amount
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 $2.03, $1.98 and $1.94 for 2013, 2012 and 2011, respectively.

See Notes to Consolidated Financial Statements.

F-39

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 statements reflect the accounts of SCANA and the following wholly-owned subsidiaries.

Regulated businesses	Nonregulated 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.

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 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. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.

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:

	2013		2012		2011
SCE&G		2.96%		2.93%		2.92%
GENCO		2.66%		2.66%		2.69%
CGT		2.19%		2.09%		2.00%
PSNC Energy		3.01%		3.01%		3.05%
Aggregate of Above		2.93%		2.90%		2.90%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 is included in the corresponding operating expenses on its income statement.

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 $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. For a discussion of when the New Units are expected to be placed in service, and a description of SCE&G’s agreement to acquire an additional 5% ownership in the New Units, see Note 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 $75.6 million at December 31, 2013 and $92.9 million at December 31, 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 consolidated balance sheet (see Note 2). Other planned major maintenance is expensed when incurred.

Through 2017, SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2013 and 2012, SCE&G incurred $18.1 million and $11.1 million, respectively, for turbine maintenance.

Nuclear refueling outages are scheduled 18 months apart. SCE&G accrued $1.2 million per month from January 2010 through December 2012 for its portion of the outages in the spring of 2011 and the fall of 2012. Total costs for

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

the 2011 outage were $34.1 million, of which SCE&G was responsible for $22.7 million. Total costs for the 2012 outage were $32.3 million, of which SCE&G was responsible for $21.5 million. In 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 to accrue $1.4 million per month for its portion of the nuclear refueling outages that are scheduled to occur through the spring of 2020.

Goodwill

The Company considers amounts categorized by FERC as “acquisition adjustments” with carrying values of $210 million (net of writedown of $230 million) for PSNC Energy (Gas Distribution segment) and $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 its carrying 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 adopted guidance under which it has 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 is not required to proceed with the two-step quantitative assessment.

In evaluations of PSNC Energy, fair value was estimated using the assistance of an independent appraisal. In evaluations of CGT, prior to the adoption of the new guidance, estimated fair value was obtained from 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. 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 $696.8 million, stated in 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 will 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 2013, 2012 and 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.

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.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 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. Such counterparties held 48% and 44% of PSNC Energy’s natural gas inventory at December 31, 2013 and December 31, 2012, respectively, with a carrying value of $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 March 31, 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 Note 2) and 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 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 regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are recorded to expense as incurred.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Income Statement Presentation

In its consolidated statements of income, the Company presents the revenues and expenses of its regulated businesses and its retail natural gas marketing businesses (including those activities of segments described in Note 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 billed. Unbilled revenues totaled $183.1 million at December 31, 2013 and $189.8 million at December 31, 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 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 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 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 pilot basis for its electric customers; 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. Such 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 utilizing the treasury stock method. The Company has issued no securities that would have an antidilutive effect on earnings per share.

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

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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric—Cost of Fuel

SCE&G’s retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G. In 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 2012.

This April 2012 order was superseded, in part, by a December 2012 rate order in which the SCPSC authorized SCE&G to reduce the base fuel cost component of its retail electric rates and, in doing so, stated that SCE&G may not adjust its base fuel cost component prior to the 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 2013. Consistent with the December 2012 rate order, SCE&G did not request any adjustment to its base fuel cost component. In March 2013, SCE&G, ORS and the SCEUC entered into a settlement agreement accepting the proposed lower environmental fuel cost component effective with the first billing cycle of May 2013, and providing for the accrual of certain debt-related carrying costs on a portion of the under-collected balance of fuel costs. The SCPSC 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 review of base rates for fuel costs has been scheduled for 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 directing it to remove from rate base deferred income tax assets arising from capital expenditures related to the New Units and to accrue carrying costs (recorded as a regulatory asset) on those amounts during periods in which they are not included in rate base. Such carrying costs are determined at SCE&G’s weighted average long-term borrowing rate, and 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 retail electric base rates, effective January 1, 2013, and authorized an allowed return on common equity of 10.25%. The SCPSC also approved a mid-period reduction to the cost of fuel component in rates (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 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 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 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. 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 order, the SCPSC provided for a $48.7 million credit to SCE&G’s customers over two years to be offset by accelerated recognition of previously deferred state income tax credits. These tax credits were fully amortized in 2012.

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

Year	Effective	Amount
2013	First billing cycle of May	$	16.9 million
2012	First billing cycle of May	$	19.6 million
2011	First 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 2014 SCE&G submitted its annual DSM Programs filing to the SCPSC, which included, among other things, a request to (1) recover one-half of the balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2014 and to recover the remaining balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2015, (2) utilize approximately $17.8 million of the gains from the recent settlement of certain interest rate derivative instruments to offset a portion of the net lost revenues component of SCE&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 remaining balance of deferred net lost revenue as of April 30, 2014, deferred within regulatory assets resulting from the May 2013 order previously described.

Electric—BLRA

In May 2011, the SCPSC approved an updated capital cost schedule sought by SCE&G that, among other matters, incorporated then-identifiable additional capital costs of $173.9 million (SCE&G’s portion in 2007 dollars).

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

costs of approximately $1 million (SCE&G’s portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications; approximately $8 million (SCE&G’s portion in 2007 dollars) related to transmission infrastructure; and approximately $132 million (SCE&G’s portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. In addition, the order approved revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims for costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC’s order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals. 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 updated cost of debt and capital structure and on an allowed return on common equity of 11.0%. The SCPSC has approved the following rate changes under the BLRA effective for bills rendered on and after October 30 in the following years:

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
2013		No change
2012		2.10%	Increase	$	7.5 million
2011		2.10%	Increase	$	8.6 million

SCE&G’s natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred. SCE&G’s gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual reviews conducted for each of the 12-month periods ended July 31, 2013 and 2012 resulted in the SCPSC issuing an order finding that SCE&G’s gas purchasing policies and practices during each review period were reasonable and prudent.

PSNC Energy

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

PSNC Energy’s rates are established using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collection of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In October 2013, in connection with PSNC Energy’s 2013 Annual Prudence Review, the NCUC issued an order finding that PSNC Energy’s gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2013.

During the third 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 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 issued an order notifying utilities that the incremental revenue requirement impact associated with the change in the level of state income tax expense included in each utility’s cost of service would be deemed to be collected on a provisional basis (subject to refund) beginning January 1, 2014.

Regulatory Assets and Regulatory Liabilities

The Company’s cost-based, rate-regulated utilities recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Other than unrecovered plant, substantially all 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	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

Accumulated deferred income tax liabilities that arose from utility operations that have not been included in customer rates are recorded as a regulatory asset. Substantially all of these regulatory assets relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 70 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.

Under-collections—electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC which are expected to be recovered in retail electric rates over periods exceeding 12 months.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by the Company, and are expected to be recovered over periods of up to approximately 26 years.

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

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

Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. In connection with the December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are being recovered through utility rates over approximately 30 years. In connection with the October 2013 RSA order, approximately $14 million of deferred pension costs for gas operations are being recovered through utility rates over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 12 years.

Planned major maintenance related to certain fossil-fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders. SCE&G collects $18.4 million annually for such equipment maintenance. Through December 31, 2012, nuclear refueling charges were accrued during each 18-month refueling outage cycle as a component of cost of service. In connection with the December 2012 rate order, effective January 1, 2013, SCE&G 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 settlement of certain interest rate derivatives designated as cash flow hedges 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 are being recovered through utility rates over periods up to 30 years.

Unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units’ previous estimated remaining useful lives, or up to approximately 14 years. Unamortized amounts are included in rate base and are earning a current return.

DSM Programs represents deferred costs and 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 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.

F-49

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the non-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 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely.

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

The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by the SCPSC, the NCUC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, the Company could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on the Company’s results of operations, liquidity or financial position in the period the write-off would be recorded.

3. COMMON EQUITY

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.

The Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At December 31, 2013 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 SCE&G’s common stock.

Cash dividends on SCANA’s common stock were declared during 2013, 2012 and 2011 at an annual rate per share of $2.03, $1.98 and $1.94, respectively.

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

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, 2013 and 2012.

SCANA issued common stock valued at $100.9 million, $97.7 million and $97.8 million (when issued) during the years ended December 31, 2013, 2012 and 2011, respectively, which was satisfied using original issue shares, through various compensation and dividend reinvestment plans, including the Stock Purchase Savings Plan.

F-50

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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:

		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) Variable rate notes hedged by a fixed interest rate swap (fixed rate of 6.47%)

(b) May be extended through 2080

(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 swaps.

The annual amounts of long-term debt maturities for the years 2014 through 2018 are summarized as follows:

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.

F-51

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In January 2012, SCANA issued $250 million of 4.125% medium term notes due February 1, 2022. Proceeds from the sale were used to retire SCANA’s $250 million 6.25% medium term notes due February 1, 2012.

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

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, 2013, the Bond Ratio was 5.28.

Lines of Credit and Short-Term Borrowings

At December 31, 2013 and 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	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 million, $1.2 billion (of which $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 the three- year agreement expires in October 2016. These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N.A. and Morgan Stanley Bank, N.A. each provide 10.7% of the aggregate $1.8 billion credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch and UBS Loan Finance LLC each provide 8.9%, and Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 6.3%. Two other banks provide the remaining support. The Company pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented.

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

The Company pays fees to the banks as compensation for maintaining committed lines of credit. Such fees were not material in any period presented.

F-52

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. INCOME TAXES

Components of income tax expense for 2013, 2012 and 2011 are as follows:

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

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	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

F-53

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The tax effects of significant temporary differences comprising the Company’s net deferred tax liability at December 31, 2013 and 2012 are as follows:

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 2009.

Changes to Unrecognized Tax Benefits

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 in prior years, the Company had previously recorded an unrecognized tax benefit. During the first quarter of 2012, the publication of new

F-54

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

administrative guidance from the IRS allowed the Company to recognize this benefit. Since this change was primarily a temporary difference, the recognition of this benefit did not have a significant effect on the Company’s effective tax rate.

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. It is reasonably possible that this tax benefit will increase by an additional $5 million within the next 12 months. No other material changes in the status of 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. In connection with the resolution of the uncertainty and recognition of the tax benefit in 2012, during 2012 the Company reversed $2 million of interest expense which had been accrued during 2011. The Company has not recorded interest expense or penalties associated with the 2013 uncertain tax position.

6. DERIVATIVE FINANCIAL INSTRUMENTS

The Company recognizes all derivative instruments as either assets or liabilities in its 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.

Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by the Company. SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries. The Risk Management Committee, which is comprised of certain officers, including the Company’s Risk Management Officer and senior officers, apprises the Audit Committee of the Board of Directors with regard to the management of risk and brings to the Audit Committee’s attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

Commodity Derivatives

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions. Cash settlements of commodity derivatives are classified as operating activities in the consolidated statement of cash flows.

PSNC Energy hedges natural gas purchasing activities using over-the-counter options and swaps and NYMEX futures and options. PSNC Energy’s tariffs also include a provision for the recovery of actual gas costs incurred, including any costs of hedging. PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the over- or under-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes.

Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI. When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit.

F-55

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As an accommodation to certain customers, SEMI, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives. These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes.

Interest Rate Swaps

The Company may use interest rate swaps to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances. In cases in which the Company synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

In anticipation of the issuance of debt, the Company may use treasury rate lock or forward starting swap agreements that are designated as cash flow hedges. Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For the holding company or nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income.

Pursuant to regulatory orders 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, 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 settlement of these financial instruments are classified as investing activities for cash flow statement purposes.

Quantitative Disclosures Related to Derivatives

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

	Commodity and Other Energy Management Contracts (in MMBTU)
Hedge designation	Gas Distribution		Retail Gas Marketing		Energy Marketing		Total
As of 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 348,453 MMBTU related to basis swap contracts in Energy Marketing.

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

The Company was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $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.

F-56

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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	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

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

Fair Value Hedges

With regard to interest rate swaps designated as fair value hedges, any gains or losses related to the swaps or the fixed rate debt are recognized in current earnings within interest expense. The Company had no interest rate swaps designated as fair value hedges for any period presented, and the amortization of deferred gains on previously terminated swaps were not significant during any period presented.

F-57

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Cash Flow Hedges

Derivatives in Cash Flow Hedging Relationships

Millions of dollars	Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion)			Loss Reclassified from Deferred Accounts into Income (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	)
Millions of dollars	Gain or (Loss) Recognized in OCI, net of tax (Effective Portion)			Loss Reclassified from Accumulated OCI into Income, net of tax (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, 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 $1.0 million as an increase to gas cost and approximately $7.0 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels. As of December 31, 2013, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2016.

Hedge Ineffectiveness

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

F-58

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Derivatives Not Designated as Hedging Instruments

Millions of dollars	Loss Recognized in Income Location		Year Ended December 31,
			2013		2012			2011
Commodity contracts		Gas purchased for resale		—	$	(1	)	$	(2	)

Millions of dollars	Gain or (Loss) Deferred in Regulatory Accounts		Gain Reclassified from     Deferred Accounts into Income
			Location		Amount
Year Ended December 31, 2013
Interest rate contracts	$	39		Other income	$	50
Year Ended December 31, 2012
Interest rate contracts	$	—			$	—
Year Ended December 31, 2011
Interest rate contracts	$	—			$	—

The gains reclassified to other income of $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, 2013 and 2012, the Company had posted $26.8 million and $78.3 million, respectively, of collateral related to derivatives with contingent provisions that were in a net liability position. Collateral related to the positions expected to close in the next 12 months is recorded in Prepayments and other on the consolidated balance sheets. Collateral related to the noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of December 31, 2013 and 2012, the Company would have been required to post an additional $0.0 million and $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, 2013 and 2012, are $25.2 million and $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.

F-59

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Millions of dollars	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position			Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
								Financial Instruments			Cash Collateral Received		Net Amount
As of December 31, 2013
Interest rate	$	32		—		$	32	$	(1	)		—	$	31
Commodity		4		—			4		—			—		4
Energy Management		8		—			8		—			—		8
Total	$	44		—		$	44	$	(1	)		—	$	43
Balance sheet location		Prepayments and other				$	21
		Other deferred debits and other assets					23
		Total				$	44
As of December 31, 2012
Interest rate	$	73		—		$	73	$	(17	)		—	$	56
Commodity		2		—			2		—			—		2
Energy Management		13	$	(1	)		12		—			—		12
Total	$	88	$	(1	)	$	87	$	(17	)		—	$	70
Balance sheet location		Prepayments and other				$	50
		Other deferred debits and other assets					37
		Total				$	87

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

Millions of dollars	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position			Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset 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 Management		8		—			8		—			6	$	2
Total	$	28		—		$	28	$	(1	)	$	25	$	2
Balance sheet location		Other current liabilities				$	10
		Other deferred credits and other liabilities					18
		Total				$	28
As of December 31, 2012
Interest rate	$	106		—		$	106	$	(17	)	$	67	$	22
Commodity		4		—			4		—			—		4
Energy Management		13	$	(1	)		12		—			11		1
Total	$	123	$	(1	)	$	122	$	(17	)	$	78	$	27
Balance sheet location		Other current liabilities				$	80
		Other deferred credits and other liabilities					42
		Total				$	122

F-60

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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:

	As of December 31, 2013				As of December 31, 2012
Millions of dollars	Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	$	9		—	$	6		—
Interest rate contracts		—	$	32		—	$	73
Commodity contracts		2		2		1		1
Energy management contracts		1		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 for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during the periods presented.

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

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

Carrying values of short-term borrowings approximate 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.

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 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 as 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 from January 1, 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

F-61

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 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 pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below.

	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 pension benefits was $796.4 million at the end of 2013 and $874.6 million at the end of 2012. The accumulated pension benefit obligation differs from the projected pension 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
	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 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, 2013 by $1.3 million and 2012 by $1.7 million. A one percent decrease in the assumed health care cost trend rate would decrease the postretirement benefit obligation at December 31, 2013 by $1.2 million and 2012 by $1.5 million.

F-62

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Funded Status

Millions of Dollars December 31,	Pension Benefits					Other Postretirement Benefits
	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 December 31,	Pension Benefits					Other Postretirement Benefits
	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 loss (a component of common equity) as of December 31, 2013 and 2012 were as follows:

Millions of Dollars December 31,	Pension Benefits				Other Postretirement Benefits
	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 December 31,	Pension Benefits				Other Postretirement Benefits
	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, 2013 and 2012, the Company recorded within deferred debits $14.1 million and $26.8 million, respectively, attributable to Santee Cooper’s portion of shared pension costs. As of December 31, 2013 and 2012, the Company also recorded within deferred debits $12.6 million and $14.7 million, respectively, from Santee Cooper, representing its portion of the unfunded postretirement benefit obligation.

Changes in Fair Value of Plan Assets

	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

F-63

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Investment Policies and Strategies

The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the obligations of the pension plan, (2) overseeing the plan’s investments in an asset-liability framework that considers the funding surplus (or deficit) between assets and liabilities, and overall risk associated with assets as compared to 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. These 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 purpose of engaging in speculative trading are also prohibited.

The Company’s pension plan asset allocation at December 31, 2013 and 2012 and the target allocation for 2014 are as follows:

	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 2014, the expected long-term rate of return on assets will be 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 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. Additional rebalancing may occur subject to funded status improvements as part of the dynamic investment policy adopted for 2014.

F-64

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

The pension 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 represent 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 fair 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 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

F-65

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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:

Expected Benefit Payments

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 for the foreseeable future.

Net Periodic Benefit Cost

The Company records net periodic benefit cost 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	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 to defer as a regulatory asset the amount of pension cost exceeding amounts included in rates for its retail electric and gas distribution regulated operations. In connection with the SCPSC’s July 2010 electric rate order and November 2010 natural gas RSA order, SCE&G began deferring, as a regulatory asset, all pension cost related to retail electric and gas operations that otherwise would have been charged to expense. Effective in January 2013, in connection with the December 2012 rate order, SCE&G began amortizing 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 rate rider that may be adjusted annually. Similarly, in connection with the October 2013 RSA order, 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 (see Note 2).

F-66

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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	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
	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 estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2014 are as follows:

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 the 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 not significant.

Stock Purchase Savings Plan

The Company sponsors a defined contribution plan in which eligible employees may defer up to 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 were $23.4 million, $22.3 million and $21.8 million, respectively, and were made in the form of SCANA common stock.

9. SHARE-BASED COMPENSATION

The LTECP 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 LTECP 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 Awards

The 2011-2013, 2012-2014 and 2013-2015 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 granted 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. Dividend equivalents are accrued on the performance shares and the restricted share units. Payouts of performance share awards are 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%).

Compensation cost of 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 prior program cycles were paid totaling $12.2 million in 2013, $11.8 million in 2012, and $13.6 million in 2011.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Fair value adjustments for performance awards resulted in compensation expense recognized in the statements of income totaling $8.7 million in 2013, $15.0 million in 2012 and $6.1 million in 2011. Fair value adjustments resulted in capitalized compensation costs of $1.4 million in 2013, $2.7 million in 2012 and $0.9 million in 2011.

Equity Awards

No equity awards were made during any period presented, and the effects of previous such awards on the Company’s results of operations, cash flows and financial 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 $13.6 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is currently liable for up to $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station Unit 1, would be $84.8 million per incident, but not more than $12.6 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Summer Station Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin. In addition, a builder’s risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million in limits of accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premiums, SCE&G’s portion of the retrospective premium assessment would not exceed $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.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 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 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

SCE&G

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, 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 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 have allowed the Company to comply with the reinstated CAIR and will also allow it to comply with CSAPR, 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 CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule was published in the Federal Register on June 7, 2013, and is expected to be finalized May 22, 2014. The EPA expects compliance as soon as possible after July 2017 but no later than July 2020.

Additionally, the EPA is expected to issue a rule that modifies requirements for existing cooling water intake 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. These provisions, if passed, could have a material impact on the financial condition, results of operations and cash flows of the Company. The Company believes that any additional costs imposed by such regulations 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 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 states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue until 2017 and will cost an additional $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. At December 31, 2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $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. 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 $2.8 million, the estimated remaining liability at December 31, 2013. PSNC Energy expects to recover through rates any cost allocable to PSNC Energy arising from the remediation of these sites.

Claims and Litigation

The Company is engaged in various 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.

Operating Lease Commitments

The Company is obligated under various operating leases for vehicles, office space, furniture and equipment. Leases expire at various dates through 2057. Rent expense totaled approximately $14.8 million in 2013, $14.8 million in 2012 and $15.8 million in 2011. Future minimum rental payments under such leases are as follows:

	Millions of dollars
2014	$	7
2015		6
2016		4
2017		2
2018		1
Thereafter		21
Total	$	41

Guarantees

SCANA 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. SCANA is not required to recognize a liability for such guarantees unless it becomes probable that performance under the guarantees will be required. SCANA 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, 2013, the maximum future payments (undiscounted) that SCANA could be required to make under guarantees totaled approximately $1.6 billion.

Asset Retirement Obligations

The Company recognizes a liability for the present value of an ARO when incurred if 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 2013, the Company has recorded AROs of approximately $191 million for nuclear plant decommissioning (see Note 1) and AROs of approximately $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	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

11. AFFILIATED TRANSACTIONS

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

SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and selling of refined coal to reduce emissions. SCE&G accounts for this 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 $134.2 million in 2013 and $111.6 million in 2012. SCE&G’s total sales to this affiliate were $133.6 million in 2013 and $111.1 million in 2012.

12. SEGMENT OF BUSINESS INFORMATION

Reportable segments, which are described below, follow the same accounting policies as those described in 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.

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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Disclosure of Reportable Segments (Millions of dollars)

	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 Revenue		6		1		—		167		416			(590	)		—
Operating Income		679		153		—		n/a		27			51			910
Interest Expense		19		22		1		—		4			251			297
Depreciation and Amortization		297		70		3		—		26			(18	)		378
Income Tax Expense		6		33		15		4		14			151			223
Net Income		n/a		n/a		24		6		(2	)		443			471
Segment Assets		9,488		2,340		172		133		1,378			1,653			15,164
Expenditures for Assets		907		140		—		1		31			27			1,106
Deferred Tax Assets		10		27		8		2		14			(61	)		—
2012
External Revenue	$	2,446	$	764	$	413	$	543	$	45		$	(35	)	$	4,176
Intersegment Revenue		7		1		—		125		416			(549	)		—
Operating Income		668		141		n/a		n/a		22			28			859
Interest Expense		21		23		1		—		3			247			295
Depreciation and Amortization		278		67		3		—		25			(17	)		356
Income Tax Expense		7		32		7		3		15			118			182
Net Income		n/a		n/a		11		5		1			403			420
Segment Assets		8,989		2,292		153		122		1,415			1,645			14,616
Expenditures for Assets		999		123		—		1		14			(60	)		1,077
Deferred Tax Assets		9		26		10		4		17			(55	)		11
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
Net Income		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

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, the 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 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 net income consist of the unallocated net income of the Company’s regulated reportable segments.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

13. QUARTERLY FINANCIAL DATA (UNAUDITED)

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

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, 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, 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.

F-76

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”) as of December 31, 2013, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’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’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’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’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’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’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, 2013, based on the criteria established in Internal Control—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 as of and for the year ended December 31, 2013, of the Company and our report dated February 28, 2014, expressed an unqualified opinion on those financial statements.

Charlotte, North Carolina

February 28, 2014

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MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

COMMON STOCK INFORMATION

Price Range (NYSE Composite Listing):

	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 NYSE using the ticker symbol SCG. Newspaper stock listings use the name SCANA. At February 20, 2014 there were 141,144,841 shares of SCANA common stock outstanding which were held by approximately 28,121 shareholders of record.

On February 20, 2014, the closing price of SCANA common stock on the NYSE was $49.08.

DIVIDENDS PER SHARE

SCANA declared quarterly dividends on its common stock of $.5075 per share in 2013 and $.495 per share in 2012.

For a discussion of provisions that could limit the payment of cash dividends, see Financing Limits and Related Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Liquidity and Capital Resources and Note 3 to the consolidated financial statements.

F-78

PERFORMANCE GRAPH

The line graph that follows compares the cumulative TSR on our common stock over a five year period, assuming reinvestment of dividends, with the S&P Utilities Index, the S&P 500 Index and a group of peer utility industry issuers. We include the peer group index in the performance graph because we measure our TSR against this peer group index to determine whether certain performance share goals under the Long–Term Equity Compensation Plan have been met. The returns for each issuer in the peer group are weighted according to the respective issuer’s stock market capitalization at the beginning of each period.

The companies in the 2013 peer group index, with the exception of those few companies that may have merged or otherwise ceased to exist over the five-year period depicted, are listed in the Proxy Statement for the 2014 Annual Meeting under the caption “Compensation Discussion and Analysis — Long–Term Equity Compensation Plan —Performance Criteria for the 2011–2013 Performance Share Awards and Earned and Vested Awards for the 2011-2013 Performance Period” on page 31.

We periodically review and update our peer groups, which are provided to us by management’s compensation consultant, and the peer groups may differ from one period to the next because certain companies may no longer meet the compensation consultant’s requirements for inclusion (for example a change in revenues may cause a company to no longer qualify for inclusion or a company may merge or otherwise cease to exist). In addition, we may also request that management’s compensation consultant include or exclude a particular company if we have information that such a change would be appropriate.

The information set forth in this Performance Graph Section shall not be deemed to be filed with the SEC or incorporated by reference into any of our filings under the Securities Exchange Act of 1934 or the Securities Act of 1933, unless specifically incorporated by reference therein.

Comparison of 5-year Cumulative Total Shareholder Return

December 31, 2008 through December 31, 2013

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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		Positions Held During Past Five Years	Dates
Kevin B. Marsh		58	Chairman of the Board and Chief Executive Officer President and Chief Operating Officer—SCANA President and Chief Operating Officer—SCE&G	2011-present 2011-present *-2011
Jimmy E. Addison		53	Executive Vice President Chief Financial Officer Senior Vice President	2012-present *-present *-2012
Jeffrey B. Archie		56	Senior Vice President and Chief Nuclear Officer—SCE&G Senior Vice President—SCANA Vice President of Nuclear Operations—SCE&G	2009-present 2010-present *-2009
George J. Bullwinkel		65	President and Chief Operating Officer—SEMI, SCI and ServiceCare Senior Vice President—SCANA	*-present *-present
Sarena D. Burch		56	Senior Vice President—Fuel Procurement and Asset Management—SCE&G and PSNC Energy Senior Vice President—SCANA	*-present *-present
Stephen A. Byrne		54	President of Generation and Transmission and Chief Operating Officer —SCE&G Executive Vice President—SCANA Executive Vice President—Generation and Transmission—SCE&G Executive Vice President—Generation, Nuclear and Fossil Hydro—SCE&G Senior Vice President—Generation, Nuclear and Fossil Hydro—SCE&G	2011-present 2009-present 2011 2009-2011 *-2009
Paul V. Fant		60	President and Chief Operating Officer—CGT Senior Vice President—SCANA	*-present *-present
D. Russell Harris		49	President of Gas Operations—SCE&G President and Chief Operating Officer—PSNC Energy Senior Vice President—Gas Distribution—SCANA Senior Vice President—SCANA	2013-present *-present 2013-present 2012-2013
W. Keller Kissam		47	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	Senior Vice President, General Counsel and Assistant Secretary	*-present
Charles B. McFadden		69	Senior Vice President—Governmental Affairs and Economic Development—SCANA Services Senior Vice President—SCANA	*-present *-present
Martin K. Phalen		59	Senior Vice President—Administration—SCANA Vice President—Gas Operations—SCE&G	2012-present *-2012

* Indicates position held at least since March 1, 2009.

Director biographical information can be found at pages 6-8 of this Proxy Statement.

F-80

SCANA Corporation

220 Operation Way

Cayce, SC 29033

www.scana.com

Printed on Recycled Paper

Admission Ticket
MR A SAMPLE
DESIGNATION (IF ANY) ADD 1 ADD 2 ADD 3 ADD 4 ADD 5 ADD 6
C123456789
ENDORSEMENT_LINE______________ SACKPACK_____________
000004
000000000.000000 ext 000000000.000000 ext
000000000.000000 ext 000000000.000000 ext
000000000.000000 ext 000000000.000000 ext
Electronic Voting Instructions
You can vote by Internet or telephone 24 hours a day, 7 days a week
Instead of mailing your proxy, you may choose one of the two voting methods outlined below to vote your proxy.
VALIDATION DETAILS ARE LOCATED IN THE SHADED BAR BELOW.
Proxies submitted via Internet or telephone must be received by 5:00 p.m., Eastern Daylight Time, on April 23, 2014.
Vote by Internet
Go to http://proxy.georgeson.com/
Follow the steps outlined on the secure website.
Vote by telephone
Call toll free 1-877-456-7915 within the USA, US territories & Canada any time on a touch tone telephone. There is NO CHARGE to you for the call.
Follow the instructions provided by the recorded message.
Using a black ink pen, mark your votes with an X as shown in this example. Please do not write outside the designated areas.
Annual Meeting Proxy Card
1234 5678 9012 345
IF YOU HAVE NOT VOTED VIA THE INTERNET OR TELEPHONE, FOLD ALONG THE PERFORATION, DETACH AND RETURN THE BOTTOM PORTION IN THE ENCLOSED ENVELOPE.
A Proposals — The Board recommends a vote FOR all nominees:
1. Election of Class III Nominees – Term Expires 2017: 01 – John F.A.V. Cecil 02 – D. Maybank Hagood 03 – Alfredo Trujillo
For All Nominees
Withhold Authority for All Nominees
For All Nominees Except the Following: Write number(s) of nominees(s)
To vote for all nominees, mark the “For All Nominees” box. To withhold voting for all nominees, mark the “Withhold Authority for All Nominees” box. To withhold voting for a particular nominee, mark the “For All Nominees Except the Following” box and enter the number(s) corresponding with the exception(s) in the space provided. Your shares will be voted for the remaining nominees.
The Board recommends a vote FOR Proposals 2, 3 and 4:
2. Approval of the Appointment of the Independent Registered Public Accounting Firm:
For Against Abstain
3. Approval of Board-Proposed Amendments to Article 8 of our Articles of Incorporation to Declassify the Board of Directors and Provide for the Annual Election of All Directors:
4. Advisory (non-binding) Vote to Approve Executive Compensation:
B Authorized Signatures — THIS SECTION MUST BE COMPLETED FOR YOUR VOTE TO BE COUNTED. DATE AND SIGN BELOW
Please sign exactly as name(s) appear(s) hereon. Joint owners should each sign. When signing as attorney-in-fact, executor, administrator, corporate officer, trustee, guardian, or custodian, please give full title.
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C 1234567890
J N T
1UPX
1907141
MR A SAMPLE (THIS AREA IS SET UP TO ACCOMMODATE 140 CHARACTERS) MR A SAMPLE AND MR A SAMPLE AND MR A SAMPLE AND MR A SAMPLE AND MR A SAMPLE AND MR A SAMPLE AND MR A SAMPLE AND MR A SAMPLE AND
01RYQC

2014 ANNUAL MEETING ADMISSION TICKET
This Admission Ticket or proof of share ownership on the record date of March 4, 2014 is required for admittance to the meeting.
SCANA CORPORATION
April 24, 2014
8:00 A.M. REFRESHMENTS 9:00 A.M. MEETING BEGINS
LEASIDE
100 EAST EXCHANGE PLACE COLUMBIA, SC 29209
PLEASE NOTE: AUDIO OR VISUAL RECORDING AND RELATED EQUIPMENT IS STRICTLY PROHIBITED WITHOUT THE PRIOR WRITTEN APPROVAL OF THE COMPANY.
DIRECTIONS TO LEASIDE:
-From I-77 North take Exit 9A onto Garners Ferry Road.
-From I-77 South take Exit 9A and turn right at traffic light onto Garners Ferry Road.
-East Exchange Place is the first right turn off Garners Ferry Road immediately before Quality Inn & Suites.
-Follow East Exchange Place to Leaside at the end of the street. The parking lot is located in front of the building.
IF YOU HAVE NOT VOTED VIA THE INTERNET OR TELEPHONE, FOLD ALONG THE PERFORATION, DETACH AND RETURN THE BOTTOM PORTION IN THE ENCLOSED ENVELOPE.
Proxy — SCANA CORPORATION
2014 Annual Meeting of Shareholders
Proxy Solicited on behalf of the Board of Directors for Annual Meeting — April 24, 2014
The undersigned hereby appoints K.B. Marsh and J.E. Addison, or either of them, as proxies with full power of substitution, to vote all shares of SCANA Corporation common stock in the undersigned’s name on the shareholder records of SCANA Corporation, at the Annual Meeting of Shareholders on April 24, 2014, and at any adjournment thereof, as instructed on the reverse hereof, and in their discretion upon all other matters that may properly be presented for consideration at the meeting.
Shares will be voted in accordance with your instructions. If no instructions are given, the shares represented by this proxy will be voted “FOR” the election of all nominees as Directors, and “FOR” Proposals 2, 3 and 4.
(Items to be voted appear on reverse side.)
Meeting Attendance
Mark the box to the right if you plan to attend the Annual Meeting.
C Non-Voting Items
Change of Address — Please print new address below.
Comments — Please print your comments below.

March 24, 2014

TO: All Participants

SCANA Corporation

Stock Purchase Savings Plan

RE: SCANA Corporation Annual Meeting of Shareholders – April 24, 2014

Enclosed with this letter is your proxy card, which shows the number of shares of SCANA Common Stock in which you have a beneficial interest under the SCANA Corporation Stock Purchase Savings Plan (“the Plan”). You have the right to instruct Bank of America, N.A., as Trustee of the Plan, how these shares should be voted at the Annual Meeting of Shareholders. According to the provisions of the Plan, the Trustee is empowered to vote the shares held in the Plan on behalf of participants in accordance with their directions.

In order for your voting instructions to be received by the Trustee in time to be voted at the Annual Meeting of Shareholders on Thursday, April 24, 2014, your proxy must be received by Tuesday, April 22, 2014. We encourage you to vote your proxy electronically by the internet or telephone. Internet and telephone voting permit you to vote at your convenience, 24 hours a day, seven days a week. You may also complete, date, sign and return the enclosed card promptly in the envelope provided. This will enable the Trustee to obtain your instructions for voting the shares of SCANA Common Stock in your Plan account. Detailed voting instructions are included on your proxy card. In the absence of your instructions, these shares will be voted by the Trustee in the same proportion as the directed shares in the Plan are voted.

The matters to be acted upon at the meeting are more fully set forth in the Notice of Annual Meeting and Proxy Statement, which is also enclosed.

If you have any questions, you may call the SCANA Corporation Employee Stock/Pension Plans Department at 803-217-9465.

Jimmy E. Addison, Chairman

Stock Purchase Savings Plan Committee

SCANA POWER OF LIVING IMPORTANT ANNUAL MEETING INFORMATION 000004 ENDORSEMENT LINE SACKPACK MR A SAMPLE DESIGNATION (IF ANY) ADD 1 ADD 2 ADD 3 ADD 4 MMMMMMMMM ADD 5 ADD 6 MMMMMMMMMMMM Admission Ticket MMMMMMMMMMMMMMM C123456789 000000000.000000 ext 000000000.000000 ext 000000000.000000 ext 000000000.000000 ext 000000000.000000 ext 000000000.000000 ext Electronic Voting Instructions You can vote by Internet or telephone 24 hours a day, 7 days a week Instead of mailing your proxy, you may choose one of the two voting methods outlined below to vote your proxy. VALIDATION DETAILS ARE LOCATED IN THE SHADED BAR BELOW. Proxies submitted via Internet or telephone must be received by 5:00 p.m., Eastern Daylight Time, on April 22, 2014. Vote by Internet Go to http://proxy.georgeson.com/ Follow the steps outlined on the secure website. Vote by telephone Call toll free 1-877-456-7915 within the USA, US territories & Canada any time on a touch tone telephone. There is NO CHARGE to you for the call. Follow the instructions provided by the recorded message. Using a black ink pen, mark your votes with an X as shown in this example. Please do not write outside the designated areas. X Annual Meeting Proxy Card 1234 5678 9012 345 IF YOU HAVE NOT VOTED VIA THE INTERNET OR TELEPHONE, FOLD ALONG THE PERFORATION, DETACH AND RETURN THE BOTTOM PORTION IN THE ENCLOSED ENVELOPE. A Proposals — The Board recommends a vote FOR all nominees: 1. Election of Class III Nominees – Term Expires 2017: 01 – John F.A.V. Cecil 02 – D. Maybank Hagood 03 – Alfredo Trujillo + For All Nominees Withhold Authority For All Nominees For All Nominees Except the Following: Write number(s) of nominees(s) To vote for all nominees, mark the “For All Nominees” box. To withhold voting for all nominees, mark the “Withhold Authority for All Nominees” box. To withhold voting for a particular nominee, mark the “For All Nominees Except the Following” box and enter the number(s) corresponding with the exception(s) in the space provided. Your shares will be voted for the remaining nominees. The Board recommends a vote FOR Proposals 2, 3 and 4: 2. Approval of the Appointment of the Independent Registered Public Accounting Firm: 3. Approval of Board-Proposed Amendments to Article 8 of our Articles of Incorporation to Declassify the Board of Directors and Provide for the Annual Election of All Directors: 4. Advisory (non-binding) Vote to Approve Executive Compensation: B Authorized Signatures — THIS SECTION MUST BE COMPLETED FOR YOUR VOTE TO BE COUNTED. DATE AND SIGN BELOW Please sign exactly as name(s) appear(s) hereon. Joint owners should each sign. When signing as attorney-in-fact, executor, administrator, corporate officer, trustee, guardian, or custodian, please give full title. Date (mm/dd/yyyy) — Please print date below. Signature 1 — Please keep signature within the box. Signature 2 — Please keep signature within the box. C 1234567890 J N T MR A SAMPLE (THIS AREA IS SET UP TO ACCOMMODATE 140 CHARACTERS) MR A SAMPLE AND MR A SAMPLE AND MR A SAMPLE AND MR A SAMPLE AND MR A SAMPLE AND MMMMMMM1UPX 1907143 MR A SAMPLE AND MR A SAMPLE AND MR A SAMPLE AND + 01RYSC

2014 ANNUAL MEETING ADMISSION TICKET This Admission Ticket or proof of share ownership on the record date of March 4, 2014 is required for admittance to the meeting. SCANA CORPORATION April 24, 2014 8:00 A.M. REFRESHMENTS 9:00 A.M. MEETING BEGINS LEASIDE 100 EAST EXCHANGE PLACE COLUMBIA, SC 29209 PLEASE NOTE: AUDIO OR VISUAL RECORDING AND RELATED EQUIPMENT IS STRICTLY PROHIBITED WITHOUT THE PRIOR WRITTEN APPROVAL OF THE COMPANY. DIRECTIONS TO LEASIDE: -From I-77 North take Exit 9A onto Garners Ferry Road. -From I-77 South take Exit 9A and turn right at traffic light onto Garners Ferry Road. -East Exchange Place is the first right turn off Garners Ferry Road immediately before Quality Inn & Suites. -Follow East Exchange Place to Leaside at the end of the street. The parking lot is located in front of the building. IF YOU HAVE NOT VOTED VIA THE INTERNET OR TELEPHONE, FOLD ALONG THE PERFORATION, DETACH AND RETURN THE BOTTOM PORTION IN THE ENCLOSED ENVELOPE. SCANA POWER FOR LIVING + Proxy — SCANA CORPORATION 2014 Annual Meeting of Shareholders Proxy Solicited on behalf of the Board of Directors for Annual Meeting — April 24, 2014 The undersigned hereby appoints K.B. Marsh and J.E. Addison, or either of them, as proxies with full power of substitution, to vote all shares of SCANA Corporation common stock in the undersigned’s name on the shareholder records of SCANA Corporation, at the Annual Meeting of Shareholders on April 24, 2014, and at any adjournment thereof, as instructed on the reverse hereof, and in their discretion upon all other matters that may properly be presented for consideration at the meeting. Shares will be voted in accordance with your instructions. If no instructions are given, the shares represented by this proxy will be voted “FOR” the election of all nominees as Directors, and “FOR” Proposals 2, 3 and 4. (Items to be voted appear on reverse side.) Meeting Attendance Mark the box to the right if you plan to attend the Annual Meeting. C Non-Voting Items Change of Address — Please print new address below. Comments — Please print your comments below.