Edgar Filing: SCANA CORP

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

SCHEDULE 14A

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 2007 Proxy Materials



				Chairman's Letter, Notice of Annual Meeting, Proxy Statement for Annual Meeting, Annual Financial Statements, Management's Discussion and Analysis and Related Annual Report Information

March 16, 2007

Dear Shareholders:

You are cordially invited to attend the Annual Meeting of Shareholders to be held at 9:00 a.m., Eastern Daylight Time on Thursday, April 26, 2007. The meeting will be held at The John Monroe J. Holliday Alumni Center at The Citadel, 69 Hagood Avenue, Charleston, South Carolina 29403.

Enclosed is SCANA's proxy statement and form of proxy for the 2007 Annual Meeting. The approximate date of mailing for this proxy statement and form of proxy is March 16, 2007. We are including SCANA's annual 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.

•: A Notice of Annual Meeting identifying the two proposals that will be presented at the Annual Meeting is enclosed.
•: At the meeting, we will give you a brief report on SCANA's 2006 business results.
•: If you vote by mail and plan to attend the meeting, please so indicate on your proxy card. If you vote by telephone or through the Internet, please follow the instructions to indicate if you plan to attend the Annual Meeting.
•: If you will need special assistance at the meeting, please contact the office of the Corporate Secretary, Mail Code 13-4 at SCANA Corporation's principal executive offices, 1426 Main Street, Columbia, South Carolina 29201 or call toll-free 1-866-217-9683 no later than Thursday, April 19, 2007.
•: Refreshments will be served beginning at 8:00 a.m.

Your vote is important. We encourage you to read this 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 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 your proxy card.

Sincerely,

William B. Timmerman
Chairman of the Board,
President and Chief Executive Officer

Table of Contents

			Page
CHAIRMAN'S LETTER TO SHAREHOLDERS
NOTICE OF ANNUAL MEETING
PROXY STATEMENT
	INFORMATION ABOUT THE SOLICITATION OF PROXIES		1
	VOTING PROCEDURES		1
	PROPOSAL 1 — ELECTION OF DIRECTORS		4
	NOMINEES FOR DIRECTORS		5
	CONTINUING DIRECTORS		6
	BOARD MEETINGS — COMMITTEES OF THE BOARD		8
	GOVERNANCE INFORMATION		11
	RELATED PARTY TRANSACTIONS		14
	SHARE OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		15
	EXECUTIVE COMPENSATION		17
		COMPENSATION DISCUSSION AND ANALYSIS	17
		COMPENSATION COMMITTEE REPORT	31
		SUMMARY COMPENSATION TABLE	32
		2006 GRANTS OF PLAN-BASED AWARDS	34
		OUTSTANDING EQUITY AWARDS AT 2006 FISCAL YEAR-END	35
		2006 OPTION EXERCISES AND STOCK VESTED	36
		PENSION BENEFITS	37
		2006 NONQUALIFIED DEFERRED COMPENSATION	39
		POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL	41
		DIRECTOR COMPENSATION	49
	PERFORMANCE GRAPH		52
	AUDIT COMMITTEE REPORT		53
	PROPOSAL 2 — APPROVAL OF APPOINTMENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		54
	OTHER INFORMATION		55
FINANCIAL APPENDIX
Index to Annual Financial Statements, Management's Discussion and Analysis and Related Annual Report Information			F-1

NOTICE OF ANNUAL MEETING

Meeting Date:	Thursday, April 26, 2007
Meeting Time:	9:00 a.m., Eastern Daylight Time
Meeting Place:	The John Monroe J. Holliday Alumni Center The Citadel 69 Hagood Avenue Charleston, South Carolina 29403
Meeting Record Date:	March 9, 2007
Meeting Agenda:	1)	Election of three Class II Directors
	2)	Approval of Appointment of Independent Registered Public Accounting Firm

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 Offices, 1426 Main Street, Columbia, South Carolina 29201, during business hours from March 16, 2007 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 using the admission ticket, please remember to detach it from your proxy card before mailing. 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 9, 2007.

By Order of the Board of Directors,

Lynn M. Williams
Corporate Secretary

SCANA Corporation
1426 Main Street
Columbia, South Carolina 29201

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 2007 Annual Meeting of Shareholders, which will be held at 9:00 a.m., Eastern Daylight Time on Thursday, April 26, 2007, and at any adjournment or postponement of the meeting. The meeting will be held at The John Monroe J. Holliday Alumni Center at The Citadel, 69 Hagood Avenue, Charleston, South Carolina 29403. These proxy materials are first being mailed to shareholders of record on or about March 16, 2007.

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 Annual Meeting if our records show that you were a shareholder of record on March 9, 2007, the record date.

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 telephone using the toll-free number shown on 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, DO NOT return your proxy card.

Vote Through The Internet:

You may vote through the Internet. The website for Internet voting is shown on 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, DO NOT return your proxy card.

Vote By Mail:

If you choose to vote by mail, mark the enclosed proxy card, date and sign it, detach your meeting admission ticket and return your proxy card to SCANA in the enclosed postage-paid envelope. If you indicate your voting choices on your proxy card, your shares will be voted according to your instructions. If your proxy card is signed and returned without

specifying choices, the shares will be voted FOR all director nominees and FOR Proposal 2.

Shares Held In Street Name

If you hold shares in street name, you may direct your vote by submitting voting instructions to your broker or nominee. Please refer to the voting instruction card provided by your broker or nominee.

Changing Or Revoking Your Proxy Vote

You may change or revoke your proxy instructions at any time prior to the vote at the Annual Meeting. For shares held 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. For shares held 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 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.

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.

Vote Required and Method of Counting Votes

At the close of business on the record date, March 9, 2007, there were 116,647,227 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 election of directors and on the approval of the appointment of Deloitte & Touche LLP as SCANA's independent registered public accounting firm even if the broker or nominee does not receive voting instructions from you.

Proposal 1 — Election of Directors

A plurality of the votes cast is required for the election of directors. "Plurality" means that if there are more nominees than positions to be filled, the individuals who receive the largest number of votes cast for directors will be elected as directors. Votes indicated as "withheld" and broker "non-votes" will not be cast for nominees, but will have no effect on the outcome of the election.

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 Appointment of 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.

Other Business

The Board knows of no other matters to be presented for shareholder action at the meeting. If other matters are properly brought before the meeting, the proxy agents named on the accompanying proxy card intend to vote the shares represented by them in accordance with their best judgment.

View Proxy Statements and Annual Report Information Through the Internet

SCANA shareholders may view proxy statements and annual report information through the Internet. 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.

PROPOSAL 1 — ELECTION OF DIRECTORS

SCANA currently has 11 directors. The Board is divided into three classes with the members of each class usually serving a three-year term. The terms of the Class II Directors will expire at the Annual Meeting. The Board has decided to nominate the existing Class II Directors, Messrs. Hipp, Stowe and York for reelection at the Annual Meeting. The terms of the Class II Directors elected at the Annual Meeting, except Mr. Hipp, will expire in 2010. In accordance with the Company's articles of incorporation, Mr. Hipp's term will expire at the Annual Meeting in 2009, which is the meeting preceding his reaching mandatory retirement age.

The proxy agents identified on your proxy card intend to vote the shares represented by your proxy FOR the election of the nominees named above unless you withhold authority to vote for any or all of such nominees.

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

Information about Directors and Nominees

The information set forth on the following pages concerning the nominees and continuing directors has been furnished to SCANA by such persons. Each of the directors is also a director of South Carolina Electric & Gas Company, a subsidiary of SCANA. There are no family relationships among any of SCANA's directors, director nominees or executive officers.

NOMINEES FOR DIRECTORS

Nominees for Class II Directors—Terms to Expire at the Annual Meeting in 2010*

		W. Hayne Hipp (Age 67) Director since 1983
		Mr. Hipp has been a private investor since The Liberty Corporation's acquisition in January 2006. Prior to its acquisition, Mr. Hipp served as Chairman, Chief Executive Officer and a director of the Liberty Corporation, a broadcasting holding company headquartered in Greenville, South Carolina. Mr. Hipp held these positions for more than five years.
		Harold C. Stowe (Age 60) Director since 1999
		Mr. Stowe has been acting Dean of the Wall College of Business at Coastal Carolina University in Conway, South Carolina since June 2006. From February 2005 to May 2006, Mr. Stowe was retired from his position as President of Canal Holdings, LLC, a forest products industry company, located in Conway, South Carolina. Mr. Stowe served as President of Canal Holdings, LLC, and its predecessor company, since March 1997. Mr. Stowe is a director of Ruddick Corporation, in Charlotte, North Carolina.
		G. Smedes York (Age 66) Director since 2000
		Mr. York is Chairman and Treasurer of York Properties, Inc., a full-service commercial and residential real estate company, in Raleigh, North Carolina. Mr. York has been associated with York Properties, Inc. since 1970. Mr. York is also Chairman of the Board of York Simpson Underwood, a residential real estate brokerage company, and of McDonald-York, Inc., a general contractor, both in Raleigh, North Carolina.

* Mr. Hipp's term will expire at the Annual Meeting in 2009.

CONTINUING DIRECTORS

Class III Directors—Terms to Expire at the Annual Meeting in 2008

		Bill L. Amick (Age 63) Director since 1990
		Mr. Amick has been the Chairman of The Amick Company, a residential and resort property real estate development company, since his retirement in October 2006 from Amick Farms, Inc., Amick Processing, Inc. and Amick Broilers, Inc., a vertically integrated broiler operation. Prior to his retirement, he served as Chairman of the Board of the Amick entities, all of which are located in Batesburg, South Carolina. He held those positions for more than five years. Mr. Amick is a director of Blue Cross and Blue Shield of South Carolina.
		Sharon A. Decker (Age 50) Director since 2005
		Mrs. Decker is the founder and has been the principal of The Tapestry Group LLC, a faith-based consulting and communications company, located in Rutherfordton, North Carolina, since September 2004. Mrs. Decker previously served as president of Tanner Holdings, LLC and Doncaster, apparel manufacturers, from August 1999 until September 2004. Mrs. Decker is a director of Coca-Cola Bottling Company Consolidated, Inc. and Family Dollar Stores, Inc., both in Charlotte, North Carolina.
		D. Maybank Hagood (Age 45) Director since 1999
		Mr. Hagood has been President and Chief Executive Officer of Southern Diversified Distributors, Inc., a provider of logistic and distribution services, located in Charleston, South Carolina, since November 2003. Mr. Hagood also has been President and Chief Executive Officer of William M. Bird and Company, Inc., a subsidiary of Southern Diversified Distributors, Inc., a wholesale distributor of floor covering materials, in Charleston, South Carolina, since 1993.
		William B. Timmerman (Age 60) Director since 1991
		Mr. Timmerman has been Chairman of the Board and Chief Executive Officer of SCANA since March 1997. He has been President of SCANA since December 1995.

Class I Directors—Terms to Expire at the Annual Meeting in 2009

		James A. Bennett (Age 46) 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. Previously, he was President and Chief Executive Officer of South Carolina Community Bank, in Columbia, South Carolina, from May 2000 to July 2002.
		Lynne M. Miller (Age 55) Director since 1997
		Ms. Miller has been an environmental consultant since her retirement from Quanta Capital Holdings, Inc., a specialty insurer, in August 2006. From August 2005 to August 2006 she was a Senior Business Consultant at Quanta Capital Holdings. From April 2004 through July 2005, she was President of Quanta Technical Services LLC. She was Chief Executive Officer of Environmental Strategies Consulting LLC, a division of Quanta Technical Services LLC, from September 2003 through March 2004. 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. and its name was changed to Environmental Strategies Consulting LLC. Ms. Miller is a director of Adams National Bank, a subsidiary of Abigail Adams National Bancorp, Inc., in Washington, D.C.
		Maceo K. Sloan (Age 57) 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 is a trustee of Teachers Insurance Annuity Association-College Retirement Equity Fund (TIAA-CREF) Funds Boards, Chairman of the Board of M&F Bancorp, Inc. and a director of its subsidiary, Mechanics and Farmers Bank, in Durham, North Carolina.

BOARD MEETINGS — COMMITTEES OF THE BOARD

The Board held four meetings in 2006. Each director attended at least 75% of all meetings of the Board and committees of which he or she was a member during 2006. Directors are expected, but not required, to attend the annual shareholders meeting absent extenuating circumstances. All of the directors attended the 2006 Annual Meeting.

The tables below identify the members and briefly summarize the responsibilities of the Board's committees, which include the Executive Committee, the Human Resources Committee, the Nominating Committee, the Governance Committee, the Audit Committee and the Nuclear Oversight Committee. The charters of the Human Resources Committee, the Nominating Committee, the 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, 1426 Main Street, Mail Code 13-4, Columbia, South Carolina 29201.

NAME OF COMMITTEE AND MEMBERS	PRINCIPAL FUNCTIONS OF THE COMMITTEE		NUMBER OF MEETINGS IN 2006


EXECUTIVE COMMITTEE W. B. Timmerman, Chairman B. L. Amick W. H. Hipp L. M. Miller M. K. Sloan G. S. York		Authorized to exercise 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 to advise the Chief Executive Officer on other matters important to the Company.	0

HUMAN RESOURCES	•	reviews and makes recommendations to the Board with respect to	3
COMMITTEE		compensation plans
	•	recommends to the Board persons to serve as senior officers of
G. S. York, Chairman		SCANA and its subsidiaries
J. A. Bennett	•	recommends to the Board salary and compensation levels, including
W. C. Burkhardt		fringe benefits, for officers of SCANA and its subsidiaries
S. A. Decker	•	approves goals and objectives with respect to the compensation of
D. M. Hagood		the Chief Executive Officer, evaluates the Chief Executive Officer's
L. M. Miller		performance and sets his compensation based on this evaluation
M. K. Sloan	•	reviews succession and continuity planning with the
		Chief Executive Officer
	•	reviews the investment policies of SCANA's 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 SCANA's operating performance relative to its bonus and
		incentive programs
	•	reviews management's compensation, discussion and analysis on executive compensation prior to its inclusion in the Company's proxy statement
	•	approves the inclusion of a Compensation Committee Report in the Company's proxy statement
	•	executes the duties, responsibilities and authority set forth in the Human Resources Committee Charter
	•	evaluates annually its own performance and the adequacy of its charter


NOMINATING	•	recommends the slate of director nominees to be presented for	1*
COMMITTEE		election at each annual meeting and director nominees to fill vacancies
	•	reviews and evaluates shareholder nominees for director in
B. L. Amick, Chairman		accordance with the nominating criteria
J. A. Bennett	•	evaluates the qualifications and performance of incumbent directors
W. C. Burkhardt	•	reviews the independence of directors and makes recommendations
S. A. Decker		regarding director independence to the Board
D. M. Hagood	•	monitors the orientation and education needs of the directors
L. M. Miller	•	reviews the level of stock ownership of directors to ensure
M. K. Sloan		compliance with minimum standards
	•	reviews reports and disclosures of insider and affiliated
		party transactions and makes recommendations to the Board on
		such transactions
	•	reviews director compensation and recommends changes to the
		Board
	•	executes the duties, responsibilities and authority set forth in
		the Nominating Committee Charter
	•	evaluates annually its own performance and the adequacy of
		its charter

GOVERNANCE	•	reviews annually, and revises as necessary, SCANA's Governance	1*
COMMITTEE		Principles
	•	recommends assignments of directors to serve on Board committees
B. L. Amick, Chairman	•	initiates and oversees an annual evaluation of the Board's
W. H. Hipp		effectiveness and assists and provides guidance to the Board in
H. C. Stowe		performing the Board's annual self evaluation
	•	evaluates periodically the size, composition and organizational
		and operational structure of the Board and recommends to the
		Board any changes
	•	executes the duties, responsibilities and authority set forth in
		the Governance Committee Charter
	•	evaluates annually its own performance and the adequacy of its
		charter

AUDIT COMMITTEE	•	periodically meets separately with management, internal auditors	8
(Established in accordance		and the independent registered public accounting firm to discuss
with Section 3(a)(58)(A) of		and evaluate the scope and results of audits and SCANA's
the Securities Exchange		accounting procedures and controls
Act of 1934)	•	reviews major issues regarding accounting principles and financial
		statement preparation
H. C. Stowe, Chairman**	•	reviews SCANA's financial statements before submission to the
W. C. Burkhardt		Board for approval and prior to dissemination to shareholders, the
D. M. Hagood		public or regulatory agencies
M. K. Sloan	•	appoints (subject to ratification by the shareholders) the independent
		registered public accounting firm
	•	sets compensation of independent registered public accounting firm
	•	reviews SCANA's corporate compliance and risk management
		programs
	•	executes the duties, responsibilities and 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


NUCLEAR OVERSIGHT	•	monitors SCANA's nuclear operations	4
COMMITTEE	•	meets periodically with SCANA's management to discuss and
		evaluate nuclear operations, including regulatory matters,
L. M. Miller, Chairman		operating results, training and other related topics
J. A. Bennett	•	periodically tours the V.C. Summer Nuclear Station and training
S. A. Decker		facilities
G. S. York	•	reviews with the Institute of Nuclear Power Operations, on a
		periodic basis, its appraisal of SCANA's nuclear operations
	•	periodically presents an independent report to the Board on the
		status of SCANA's nuclear operations

*The former Nominating and Governance Committee also met once prior to being divided into two separate Committees.

**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.

GOVERNANCE INFORMATION

Governance Principles

Our Governance Principles can be found on SCANA's website at www.scana.com under the "Company Profile — Corporate Governance" caption, and are also available in print upon request to the Corporate Secretary, SCANA Corporation, 1426 Main Street, Mail Code 13-4, Columbia, South Carolina 29201.

Director Independence

SCANA's Governance Principles require that a majority of SCANA's directors be independent under the New York Stock Exchange Listing Standards and under any Director Qualification Standards recommended by the Nominating Committee. 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 SCANA 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 the long-term interests of SCANA and its shareholders as a whole, to deal at arm's length with SCANA, and to disclose all circumstances material to the director that might be perceived as a conflict of interest.

The SCANA Director Qualification Standards also prohibit Audit Committee members from having any direct or indirect financial relationship with SCANA other than the ownership of SCANA securities and compensation as directors and committee members. The Board has determined that all of its directors except Mr. Timmerman, who is SCANA's Chief Executive Officer, are independent under the New York Stock Exchange Listing Standards and SCANA's Governance Principles. The Board has also determined that each member of the Audit Committee, Human Resources Committee, Governance Committee and Nominating Committee is independent under the New York Stock Exchange Listing Standards and SCANA's Governance Principles.

Executive Sessions of Non-Management Directors

To promote open discussion among themselves, SCANA's non-management directors meet regularly in executive session without management participation. The Chairs of the Audit, Human Resources, Nuclear Oversight, Nominating, and Governance Committees of the Board each preside as the Chair at meetings of non-management directors at which the principal items to be considered are within the scope of authority of his or her committee. The Board believes this procedure provides for leadership at all meetings of non-management directors without the need to designate a lead director.

Director Nominations Process

The Nominating Committee recommended to the Board the individuals nominated for director positions at the 2007 Annual Meeting.

The Nominating 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 Committee for consideration as a Board of Directors' nominee, such shareholder must submit in writing to the Nominating 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 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 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 Committee.

Director candidates recommended by shareholders will not be considered for recommendation by the Nominating 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 Committee chooses not to recommend a shareholder candidate as a Board of Directors' nominee, or if a shareholder chooses to personally nominate a candidate as a nominee, 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 SCANA's bylaws. Any shareholder may request a copy of the relevant bylaw provision by writing to the office of the Corporate Secretary, SCANA Corporation, 1426 Main Street, Mail Code 13-4, Columbia, South Carolina 29201. Nominations not made in accordance with these requirements may be disregarded by the presiding officer of the meeting, and upon his instructions, the voting inspectors shall disregard all votes cast for each such nominee.

Director Qualification Criteria

In identifying and evaluating potential nominees, the Nominating 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 director qualification standards in SCANA's Governance Principles, including SCANA's policy that a majority of its directors be independent.

The Nominating 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. The director qualification standards set forth in SCANA's Governance Principles state that:

•: Directors must possess and have demonstrated the highest personal and professional ethics, integrity and values consistent with those of SCANA.
•: Directors must be unencumbered and unbiased and able to make business judgments in the long-term interests of SCANA and its shareholders as a whole.
•: Directors are required to deal at arm's length with SCANA and its subsidiaries and to 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 SCANA's 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.
•: Directors who serve as chief executive officers or equivalent positions should not serve on more than two boards of public companies in addition to the SCANA Board. Other directors should not serve on more than four boards of public companies in addition to the SCANA Board.
•: 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.
•: Directors are required to own a minimum of 100 shares of SCANA common stock. A significant financial commitment to SCANA in the form of ownership of common stock is encouraged and will be evaluated by the Nominating Committee in the course of its work.

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

Shareholders and other interested parties can communicate with the Board or with the non-management directors as a group or with any director by writing to them, c/o Lynn M. Williams, Corporate Secretary, SCANA Corporation, 1426 Main Street, Mail Code 13-4, Columbia, South Carolina 29201 or by sending an e-mail to independentdirectors@scana.com (for correspondence to the non-management directors) or to lmwilliams@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, nominatingchair@scana.com, or governancechair@scana.com. The Corporate Secretary may initially review communications with directors and transmit 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 substantial issues.

SCANA's Code of Conduct & Ethics

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

The full text of the Code is published on the SCANA website, at www.scana.com, under the "Company Profile — Code of Conduct" caption, and a copy is also available in print upon request to the Corporate Secretary, SCANA Corporation, Mail Code 13-4, 1426 Main Street, Columbia, South Carolina 29201. SCANA intends to disclose future amendments

to, or waivers from, certain provisions of the Code on its website within two business days following the date of such amendment or waiver.

RELATED PARTY TRANSACTIONS

We require that each senior executive officer, director and director nominee complete an annual questionnaire and report all transactions with SCANA in which such persons (or their immediate family members) had or will have a direct or indirect material interest (except for salaries, directors' fees and dividends on our stock). The Company's General Counsel reviews responses to the questionnaires, and if any such transactions are disclosed, they are reviewed by the Nominating Committee, and if appropriate, submitted to the Board for approval. The Company does not, however, have a formal written policy or procedure for approval or ratification of such transactions.

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 the employment of family members of executive officers or directors. There were no such transactions during the year ended December 31, 2006.

SHARE OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

SECURITY OWNERSHIP OF MANAGEMENT

The following table lists shares of SCANA common stock beneficially owned on February 22, 2007, by each director, each nominee, each person named in the Summary Compensation Table on page 32, and all directors and executive officers as a group.

Name of Beneficial Owner		Amount and Nature of Beneficial Ownership^(1)(2)(4)(5)		Percent of Class
W. B.	Timmerman	61,090		*
J. E.	Addison	14,040		*
K. B.	Marsh	19,156		*
F. P.	Mood, Jr.	1,568		*
G. J.	Bullwinkel, Jr.	37,379		*
S. A.	Byrne	31,467	⁽³⁾	*
B. L.	Amick	11,669		*
J. A.	Bennett	3,808		*
W. C.	Burkhardt	13,122		*
S. A.	Decker	2,205		*
D. M.	Hagood	1,541		*
W. H.	Hipp	15,773		*
L. M.	Miller	3,738		*
M. K.	Sloan	1,910		*
H. C.	Stowe	2,850		*
G. S.	York	13,770		*
All executive officers and directors as a group (20 persons)		298,541	⁽⁶⁾	*

: *Less than 1%
(1): Includes shares purchased through February 22, 2007, by the Trustee under SCANA's Stock Purchase Savings Plan.
(2): Hypothetical shares acquired under the Director Compensation and Deferral Plan are not included in the above table. These hypothetical shares do not have voting rights. As of February 22, 2007, each of the following directors had acquired under the plan the number of hypothetical shares following his or her name: Messrs. Amick 15,575; Bennett 13,736; Burkhardt 18,594; Hagood 5,378; Hipp 12,022; Sloan 17,776; Stowe 13,146; and York 17,927; Mrs. Decker 0; and Ms. Miller 18,823.
(3): Includes shares subject to options that are currently exercisable or that will become exercisable within 60 days in the following amounts: Mr. Byrne 21,492.
(4): Hypothetical shares acquired under the Executive Deferred Compensation Plan are not included in the above table. These hypothetical shares do not have voting rights. As of February 22, 2007, each of the following officers had acquired under the plan the number of hypothetical shares following his name: Messrs. Timmerman 41,964; Addison 654; Marsh 5,157; Mood 0; Bullwinkel 18,968; and Byrne 8,368.
(5): Includes shares owned by close relatives, the beneficial ownership of which is disclaimed by the director, nominee or named executive officer, as follows: Mr. Amick 480. Also includes 2,000 shares held in a trust for the benefit of a family member of Mr. Timmerman, of which Mr. Timmerman serves as Trustee.
(6): Includes a total of 28,260 shares subject to options that are currently exercisable or that will become exercisable within 60 days.

FIVE PERCENT BENEFICIAL OWNERSHIP OF SCANA COMMON STOCK

The following table provides information about persons known by SCANA to be the beneficial owners of more than five percent of SCANA common stock as of February 14, 2007 (the deadline for filing Schedule 13G). This information was obtained from Schedules 13G filed with the Securities and Exchange Commission and has not been verified by SCANA.

Name and Address of Beneficial Owner		Amount and Nature of Beneficial Ownership		Percent of Class
SCANA Corporation Stock Purchase Savings Plan Merrill Lynch Bank & Trust Company, as Trustee 400 Colony Square, Suite 2200 1201 Peachtree Street, N.E. Atlanta, GA 30361		11,195,536	⁽¹⁾	9.60
Barclays Entities 45 Fremont Street San Francisco, CA 94105		5,869,032	⁽²⁾	5.04

⁽¹⁾: The SPSP has shared power to vote and dispose of all of these shares.
⁽²⁾: Based on a Schedule 13G filing by several Barclays entities who disclaimed the existence of a group but nonetheless aggregated their shares for filing purposes. Those Barclays entities are Barclays Global Investors, NA, Barclays Global Fund Advisors, Barclays Global Investors, Ltd, Barclays Global Investors Japan Trust and Banking Company Limited, Barclays Investors Japan Limited.

EXECUTIVE COMPENSATION

Compensation Committee Processes and Procedures

Our Human Resources Committee, which is comprised entirely of independent directors, administers our senior executive compensation program. Compensation decisions for all senior executive officers and directors are approved by the Human Resources 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 and directors.

In addition to attendance by members of the Human Resources Committee, the Committee's meetings are also regularly attended by our Chairman and Chief Executive Officer and our Senior Vice President of Human Resources. However, at each meeting the Committee also meets in executive session. The Chairman of the Committee reports the Committee's recommendations on executive compensation to the Board of Directors. Our Human Resources and Tax Departments support the Human Resources 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. The Committee has, however, historically chosen to use relevant information provided to us by management's consultant, Hewitt Associates. The Committee uses 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 to assure the Committee that our policies for compensation and benefits are competitive and aligned with utility and general industry practices.

Compensation Committee Interlocks and Insider Participation

During 2006, decisions on various elements of executive compensation were made by the Human Resources Committee. No officer, employee or former officer or any related person of SCANA or any of its subsidiaries served as a member of the Human Resources Committee.

The directors who served on the Human Resources Committee during 2006 were:

Mr. G. Smedes York, Chairman
Mr. Bill L. Amick*
Mr. James A. Bennett
Mr. William C. Burkhardt
Mrs. Sharon A. Decker
Mr. D. Maybank Hagood
Ms. Lynne M. Miller
Mr. Maceo K. Sloan

*Mr. Amick served on the Committee until August 2, 2006.

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
•: Relating the elements of the compensation program to focus on the proper balance of financial, customer-service, operational and strategic goals.

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 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 (a group of approximately ten 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."

Principal Components of Executive Compensation

During 2006, senior executive compensation consisted primarily of three key components: base salary, short-term cash incentive compensation (under the Short-Term Annual Incentive Plan) 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, termination, severance and change in control arrangements, and perquisites. The Human Resources 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 information provided by our 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.

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 is 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 be able 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 target compensation levels for all components of compensation. The market

survey information is provided to us every other year by our compensation consultant. In years in which our consultant does not provide us with market survey information, our process is to apply an aging factor to the prior year's information with assistance from our consultant based on its experience in the marketplace. Our most recent surveys were performed in 2005.

Our goal is to set base salary and short- and long-term incentive compensation for our senior executive officers at the median (50^th percentile) of compensation paid for similar positions by the companies included in the market surveys. We 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 and market factors. We do not set a target level for broad-based benefits for our senior executive officers, but our market survey information indicates that they currently are approximately at the median.

The companies included in the market surveys are a group of utilities and general industry companies of various sizes in terms of revenue. Approximately half of the companies included in the most recent market surveys had substantially the same levels of annual revenues as we had, while the remainder had revenues not greater than four times our revenues. Market survey results for each position are adjusted using regression analysis to account for these differences in company revenues. To a large extent, the companies included in the survey results were those that had agreed to participate in market surveys included in our compensation consultant's database.

The companies included in the market survey we used in connection with setting base salaries and short-term incentive compensation for 2006, and the states in which they are headquartered are listed below:

Utility Industry: AGL Resources, Inc. (GA); Ameren Corporation (MO); Aquila, Inc. (MO); Black Hills Corporation (SD); CenterPoint Energy (TX); Cinergy Corp. (OH); Cleco Corporation (LA); CMS Energy Corporation (MI); Dominion Resources, Inc. (VA); DTE Energy Company (MI); Duke Energy Corporation (NC); Edison International (CA); El Paso Electric Company (TX); FPL Group, Inc. (FL); Great Plains Energy (MO); Nicor Inc. (IL); NiSource Inc. (IN); Pepco Holdings, Inc. (DC); PNM Resources, Inc. (NM); PPL Corporation (PA); Progress Energy, Inc. (NC); Public Service Enterprise Group (NJ); Sempra Energy (CA); Southern Company (GA); WGL Holdings, Inc. (DC).

General Industry: Alliant Techsystems Inc. (MN); ALLTEL Corporation (AR); Armstrong World Industries (PA); Ball Corporation (CO); Becton Dickinson and Co. (NJ); BorgWarner Inc. (MI); Brunswick Corporation (IL); C.R. Bard, Inc. (NJ); The Clorox Company (CA); Cooper Cameron Corp. (TX); Cooper Industries (TX); Ecolab Inc. (MN); FMC Corporation (PA); Hasbro, Inc. (RI); MeadWestvaco Corporation (VA); Medtronic, Inc. (MN); Packaging Corp. of America (IL); Praxair, Inc. (CT); The Sherwin-Williams Co. (OH); Sonoco Products Company (SC); Springs Industries, Inc. (SC); Steelcase Inc. (MI); Wm. Wrigley Jr. Company (IL).

We believe the utilities included in our market surveys are an appropriate group to use for compensation comparisons because they align well with our sales and 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 surveys are appropriate to include in our comparisons because they align well with our sales and 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 marketing, business and other corporate support functions). We then attempt to match to the greatest degree possible our positions with similar positions in the survey results. For positions that do not fall specifically into the utility or non-utility group, 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 companies in determining long-term equity incentive compensation under our shareholder-approved long-term equity compensation plan, as discussed below 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. Timmerman has been our President and Chief Executive Officer for 10 years, and has been employed with us in various capacities, including Chief Financial Officer and Chief Operating Officer, for 28 years. Mr. Timmerman started his career as a certified public accountant. As our Chief Executive Officer, Mr. Timmerman has responsibility for strategic planning, development of our senior executive officers and oversight of all our operations.

Mr. Addison was appointed our Senior Vice President and Chief Financial Officer in April 2006, prior to which he had served as our Vice President — Finance since 2001. As Chief Financial Officer, he is responsible for all of our financial operations, including accounting, risk management, treasury, 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 15 years.

Mr. Marsh was appointed President and Chief Operating Officer of South Carolina Electric & Gas Company, our largest subsidiary, in April 2006, prior to which he had served as our Senior Vice President and Chief Financial Officer since 1998. As President of SCE&G, he is responsible for all of its gas and electric operations, as well as for all of our facilities and properties management. Mr. Marsh previously practiced as a certified public accountant and has been with us for 22 years.

Mr. Mood has been our Senior Vice President and General Counsel for two years. In these positions, he is responsible for overseeing our legal activities as well as our Legal, Environmental and Corporate Secretary Departments. Prior to his employment with us, Mr. Mood was in private practice as a lawyer for 37 years. Mr. Mood has previously served as Interim Dean of The University of South Carolina School of Law and as chairman of the South Carolina Board of Law Examiners, and is a permanent member of the Judicial Conference of the United States Court of Appeals for the Fourth Circuit.

Mr. Bullwinkel has been with us for 35 years. He is Senior Vice President of SCANA, as well as President and Chief Operating Officer of our subsidiary, SCANA

Energy Marketing, Inc., which is a provider of natural gas, and President of our subsidiaries, SCANA Communications, Inc. and ServiceCare, Inc. He is also responsible for senior executive oversight of our subsidiary, Public Service Company of North Carolina, Incorporated, d/b/a PSNC Energy, which is a regulated provider of natural gas in North Carolina. In these positions, he is responsible for overall operations of each of these subsidiaries.

Mr. Byrne is Senior Vice President-Generation, Nuclear and Fossil Hydro. In these positions, he is responsible for overseeing all of our activities related to nuclear power, including nuclear plant operations, core analysis, emergency planning, licensing and nuclear support services. He has been with us for 11 years, and has over 20 years experience in the nuclear industry.

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 Human Resources Committee also considers recommendations from our Chairman and Chief Executive Officer in setting compensation for senior executive officers. We also consider the senior executive's level of ownership of our common stock in relationship to the senior executive's tenure and salary level.

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

In 2006, our Human Resources Committee reviewed summaries of compensation components ("tally sheets") for all of our senior executive officers, including the Named Executive Officers. These tally sheets reflected changes in compensation from the prior year and affixed dollar amounts to each component of compensation. The Committee intends 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, and insurance, retirement and other benefits, in determining the total compensation package for each senior executive officer.

Timing of Senior Executive Officer Compensation Decisions

Annual salary reviews and adjustments and short- and long-term incentive compensation awards are routinely made in February of each year at the first regularly scheduled Human Resources Committee and Board meeting. Determinations also are made at that meeting as to whether to pay out awards under the most recently completed three-year cycle of long-term 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 or promotions of existing employees that could not be deferred until the February meeting. We routinely make our annual and quarterly earnings releases in conjunction with the quarterly meetings of our Board.

Base Salaries

Senior executive officer base salaries are divided into grade levels based on market data for similar positions and experience. The Human Resources Committee believes it is appropriate to set base salaries at a reasonable level that will provide executives with a predictable income base on which to structure their personal budgets. Accordingly, base salaries are targeted at the median (50^th percentile) of the survey data. The Human Resources Committee reviews base salaries annually and makes adjustments on the basis of an assessment of individual performance, relative levels of accountability, prior experience, breadth and depth of knowledge,

changes in market compensation practices as reflected in market survey data, and relative compensation levels within our company.

With the exception of the base salaries of Mr. Addison and Mr. Marsh, the Committee did not increase base salaries for the Named Executive Officers in 2006 based on its determination that current salaries were appropriate in light of the market survey data and relative compensation levels within our Company. The Committee increased Mr. Addison's base salary as a result of his promotion to Senior Vice President and Chief Financial Officer, and increased Mr. Marsh's base salary as a result of his transition to President and Chief Operating Officer of SCE&G, our largest subsidiary. In making the decisions with respect to the increases in base salaries for Messrs. Addison and Marsh, and the decision not to increase base salaries of the other Named Executive Officers, the Committee took into consideration recommendations of our Chief Executive Officer.

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 cycles which have historically lasted three years. Both our short-term and long-term executive incentive 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 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; provides 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 helps to align the interests of senior executive officers with those of 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 180 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 Human Resources Committee approves, the performance measures, operational goals and other terms and conditions of incentive awards for executives, including the Named Executive Officers.

The 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, and on each senior executive officer's level of performance as compared to his or her individual financial and strategic objectives. 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.

The plan allows for an increase or decrease in short-term incentive award payout of up to 20% of the target award based on an individual's performance in meeting individual financial and strategic objectives. The plan also allows for an increase or decrease in award payout of up to 50% of the target award based on the extent to which we achieve our pre-determined financial objectives. However, 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 Human Resources Committee determines that actual results warrant a lower payout.

For each Named Executive Officer, except Mr. Timmerman, the Short-Term Annual Incentive Plan placed equal emphasis on the following financial and business objectives for 2006:

•: Achieving earnings per share targets which were set to reflect the Company's published earnings per share growth guidance; and
•: Achieving annual business objectives relating to our four critical success factors: cost effective operations, profitable growth, excellence in customer service, and developing our people.

For Mr. Timmerman, the Short-Term Annual Incentive Plan placed equal emphasis in 2006 on achieving the earnings per share targets and performance of our senior executive officers.

The specific objectives for each senior executive officer are weighted according to the extent to which the executive will be responsible for results of the objectives. The weightings assigned to the business objectives for each Named Executive Officer for 2006 are shown in the table below:

2006 Weightings Assigned to Each Business Performance Objective
for Named Executive Officers

Objective	Mr. Timmerman		Mr. Marsh		Mr. Addison		Mr. Mood		Mr. Bullwinkel		Mr. Byrne
Senior Staff Performance	50	%
Financial Results	50	%	50	%	50	%	50	%	50	%	50	%
Cost Effective Operations			20	%	30	%			5	%	40	%
Profitable Growth			10	%	10	%			5	%
Customer Service			10	%	10	%	37.5	%	40	%	10	%
Developing our People			10	%			12.5	%

We did not achieve our earnings per share targets for 2006 and, accordingly, we did not make any earnings per share-related payouts under the Short-Term Annual Incentive Plan. However, we achieved our business objectives and our senior executive officers achieved their individual financial and strategic objectives. Accordingly, we made payouts to our senior executive officers, including our Named Executive Officers, with respect to the business and individual financial and strategic objectives portions of the plan. As further discussed below under the caption "—Discretionary Bonus Award," we also made a 20% discretionary bonus award to each of our senior executive officers, including our Named Executive Officers, as permitted by the plan. The 2006 Short-Term Incentive Plan awards based on our achieving our business objectives and our Named Executive Officers' achieving their individual objectives are reflected in the Summary Compensation Table under the column

"Non-Equity Incentive Plan Compensation," and the discretionary bonus award under the plan is reflected in the Summary Compensation Table under the column "Bonus."

Individual Financial and Strategic Objectives on which 2006 Short-Term Annual Incentive Awards were Based

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

Mr. Timmerman's award was based on his contributions and his leadership of other senior executives in achieving our overall corporate strategic plan objectives. For 2006, our strategic objectives, which were included in business unit objectives, were leveraging employee and business development; ensuring the security of our people, assets and operations; optimizing the use of our utility assets; effectively addressing new environmental, regulatory and legislative issues; and effectively managing fuel and healthcare costs.

Mr. Addison's award was based on his successful efforts toward maintaining financial reporting compliance processes and procedures that meet the requirements of the Sarbanes-Oxley Act; his analysis and documentation relating to electric and gas regulatory decisions for 2006; his oversight of the successful implementation of transition of certain information technology systems and system testing; and progress toward development of a plan relating to insurance coverage for catastrophic property loss risks.

Mr. Marsh's award was based on his progress toward developing plans to enhance our succession strategy; progress toward developing, obtaining approval of and preparing for implementation of a cost effective and responsible environmental strategy; oversight of efforts to optimize the allocation of natural gas assets and implementation of the transition to open access; identification and tracking of compliance with existing and emerging regulations; and effectiveness in managing the operation and maintenance and capital budgets.

Mr. Mood's award was based on his effective oversight of implementation of annual internal reporting and assessments relating to environmental issues; fostering collaborative relationships between our legal department and our business units; effective oversight of training relating to Federal Energy Regulatory Commission regulations; and effective oversight of the legal, environmental, and corporate secretary departments' staffing and management.

Mr. Bullwinkel's award was based on his efforts in connection with the successful implementation by one of our subsidiaries of automated meter-reading in designated service areas; oversight of the successful integration of marketing efforts of one of our subsidiaries with its strategic partners; oversight of the successful development and implementation of a plan to provide additional staffing, training, equipment and office space needed to serve customers in one of our subsidiaries' service areas; and improvement of customer service at one of our subsidiaries.

Mr. Byrne's award was based on his oversight of our achieving a system availability factor beyond targeted levels for our fossil hydro operations; demonstration of environmental responsibility of our fossil hydro operations; oversight of successful implementation of certain system modifications during refueling at our nuclear plant; oversight of a very successful refueling outage; and oversight of progress toward licensing, site selection, vendor selection and project development agreement for a potential new nuclear plant.

Discretionary Bonus Award

The 20% discretionary bonus award was recommended to our Human Resources Committee by our Chief Executive Officer, and both the Human Resources Committee and the Board approved the discretionary payout. The bases for the discretionary portion of the award are as follows:

•: Two primary factors that held down financial performance (mild weather and loss of industrial customers) were not within the control of our employees;
•: Our management team has made tremendous progress this year dealing with long-term strategic issues, such as planning for future expansion of generation, coping with pending environmental challenges, and dealing with a host of federal regulatory changes that are both complex and often not well defined; and
•: There were a number of exceptional short term accomplishments in the past year, including having three of our coal fired plants rated among the 20 most efficient plants in the United States.

We believe this discretionary payment to our short-term bonus plan participants is well justified and necessary to reward and retain our critical human resources.

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 Human Resources Committee believes this approach to 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 Human Resources Committee may award under the plan include incentive and nonqualified stock options, stock appreciation rights (either alone or in tandem with a related stock option), restricted stock, performance units and performance shares. In recent years, the only long-term equity-based awards have been in the form of performance shares and performance units. These long-term equity-based awards are granted subject to satisfaction of specific performance goals. For the 2006-2008 performance period, awards under the Long-Term Equity Compensation Plan consisted solely of performance shares. We have not awarded stock options since 2002 and have no plans to do so in the foreseeable future.

Payouts of awards under the Long-Term Equity Compensation Plan may be made in cash or SCANA common stock at our discretion, but are most frequently made in cash. We believe awards of performance units and 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.

Performance Share Awards

For the 2005-2007 and 2006-2008 performance cycles, performance share awards to senior executive officers under the Long-Term Equity Compensation Plan were based on (1) our Total Shareholder Return ("TSR") relative to the TSR of a group of peer companies over the three-year periods and (2) a three-year average growth in earnings component based on our earnings per share under generally accepted accounting principles,

with adjustments to be made to account for the cumulative effects of any mandated changes in accounting principles and the effects of any sales of certain investments or impairment charges related to certain investments (we refer to this component as growth in "EPS from ongoing operations"). TSR over the three-year periods is 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.

Performance share awards 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.

Creating a new three-year cycle each year provides an opportunity to adjust the target, threshold and maximum award levels based on historical performance, and provides an ongoing long-term incentive to senior executive officers. Payouts under the 2005 and 2006 three-year cycles will be based upon the extent to which we meet our performance goals for the entire three-year periods.

Beginning with the 2007-2009 performance cycle, however, the Long-Term Equity Compensation Plan provides for performance measurement and award determination on an annual basis (rather than the above described three-year measurement and determination), with payment of awards being deferred until after the end of the three-year performance cycle. Accordingly, payouts under the 2007 three-year cycle will be earned for each year that performance goals are met during the three-year cycle, though payments will be deferred until the end of the cycle and will be contingent upon the participant's still being employed by us at the end of the cycle, subject to certain exceptions in the event of retirement, death or disability. Additionally, the payment of the EPS growth component of the 2007-2009 performance cycle awards will be based on growth in "GAAP-adjusted net earnings per share from operations" as that term is used in the Company's periodic reports and external communications. GAAP-adjusted net earnings per share from operations may reflect different or additional adjustments than are or would have been reflected in the determination of EPS from ongoing operations in prior plan cycles.

We believe that these changes for the 2007-2009 cycle will increase the effectiveness of the plan in encouraging executive retention by minimizing the impact of extraordinarily strong or poor single-year performance on award payouts. The other performance criteria adopted by the Board on recommendation of the Human Resources Committee for the 2007-2009 Plan performance cycle do not differ materially from the 2006-2008 Plan performance cycle.

2006 Long-Term Incentive Plan Awards

In 2006, we made performance share awards to each of the Named Executive Officers. The awards have a three-year cycle ending in 2008 and are payable based on our levels of performance against pre-determined measures of TSR and average growth in EPS from ongoing operations over the three-year plan cycle. Information about the performance criteria for the 2006 three-year cycle is set forth below. Information about the number of performance shares awarded for the 2006 three-year cycle is provided in the "2006 Grants of Plan-Based Awards" table on page 34.

Sixty percent of the 2006 target performance share awards are based on our TSR over the three-year plan cycle compared with the peer group of utilities set forth below:

Allegheny Energy, Inc.; Allete Inc.; Alliant Energy Corporation; Ameren Corporation;

Avista Corporation; Cinergy Corp.; Cleco Corporation; CMS Energy Corporation; Consolidated Edison, Inc.; Constellation Energy Group, Inc.; Dominion Resources, Inc.; DPL, Inc.; DTE Energy Company; Duquesne Light Holdings, Inc.; Edison International; Energy East Corporation; Entergy Corporation; FirstEnergy Corp.; FPL Group, Inc.; Great Plains Energy, Inc.; Hawaiian Electric Industries, Inc.; IDACORP, Inc.; NiSource Inc.; Northeast Utilities; NorthWestern Corporation; NSTAR; OGE Energy Corp.; Pepco Holdings, Inc.; Pinnacle West Capital Corporation; PNM Resources, Inc.; PPL Corporation; Progress Energy, Inc.; Public Service Enterprise Group, Inc.; Puget Energy, Inc.; Sierra Pacific Resources; Southern Company; TECO Energy, Inc.; UIL Holdings Corporation; UniSource Energy Corporation; Vectren Corporation; Westar Energy, Inc.; Wisconsin Energy Corporation; WPS Resources Corporation.

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-term incentive compensation 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.

Payouts based on the TSR component of the plan are scaled according to our ranking against the peer group. No payout is earned if our performance is less than the 33^rd percentile. Senior executive officers earn threshold payouts (equal to 50% of target award) if we rank at the 33^rd percentile in relation to the peer group's three-year TSR performance. Target payouts (equal to 100% of target award) occur if we rank at the 50^th percentile in relation to the peer group's three-year TSR performance. Maximum payouts (equal to 150% of target award) result if our performance ranks at or above the 75^th percentile in relation to the peer group's three-year TSR performance. Payouts are scaled between 50% and 150% based on the actual percentile achieved. No payouts may exceed 150% of the target award. Threshold, target and maximum payouts at the 33^rd, 50^th and 75^th percentiles were used because these match generally the levels used by the companies in the market survey data.

Forty percent of the 2006 performance share awards were based on meeting our projections for three-year average growth in EPS from ongoing operations. Payouts for target performance share awards granted in 2006 for the 2006-2008 performance period will be made if our three-year average growth in EPS from ongoing operations equals 3.7%. Executives would earn threshold payouts (equal to 50% of target award) at 1.7% average growth, target payouts (equal to 100% of target award) at 3.7% average growth, and maximum payouts (equal to 150% of target award) at or above 5.7% average growth. Payouts are scaled between 50% and 150% based on the actual growth in EPS from ongoing operations achieved. No payouts will occur if average growth in EPS from ongoing operations over the three-year period is less than 1.7%, and no payouts will exceed 150% of target award.

Performance share awards are denominated in shares of our common stock. The number of performance shares into which awards are denominated at grant is calculated by multiplying the Named Executive Officer's base salary by a target percentage, and dividing the product by the discounted 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 discounted stock price is provided to us by our compensation consultants. Performance share awards may be paid in stock or cash or a combination of stock

and cash at our discretion. Based on past practices, we currently anticipate that payouts will be in cash. Payouts are based on the closing market price of our stock on the last date of the performance cycle.

The allocation of 60% of awards to three-year TSR and 40% to EPS from ongoing operations was made to weight the external performance measure slightly higher than the internal performance measure.

2006 Payouts Under Performance Share Awards and Performance Unit Awards Granted in 2004

Performance Share Awards

Payouts for target performance share awards granted in 2004 for the 2004-2006 performance period were based on our achieving TSR in the top two-thirds of the TSR for the Long-Term Equity Compensation Plan peer group over the three-year period. Executives would earn threshold payouts (equal to 50% of target award) if we ranked at the 33^rd percentile in relation to the peer group's three-year TSR performance. Target payouts (equal to 100% of target award) would be earned if we ranked at the 50^th percentile in relation to the peer group's three-year TSR performance. Maximum payouts (equal to 150% of target award) would be earned if we ranked at or above the 75^th percentile in relation to the peer group's three-year TSR performance. Payouts were scaled between 50% and 150% based on the actual percentile achieved. No payouts would be earned if TSR were at less than the 33^rd percentile and no payouts would exceed 150% of the target award.

For the three-year performance period 2004-2006, our TSR was below the 33^rd percentile of the peer group's TSR which resulted in no payouts.

Performance Unit Awards

Payouts for performance unit awards granted in 2004 for the 2004-2006 performance period were based on meeting our projections for three-year average growth in EPS from ongoing operations. Senior executive officers would earn threshold payouts (equal to 50% of target award) at 2% average growth, target payouts (equal to 100% of target award) at 4% average growth and maximum payouts (equal to 150% of target award) at or above 6% average growth. Payouts were scaled between 50% and 150% based on the actual growth in EPS from ongoing operations achieved. No payouts would occur if average growth in EPS from ongoing operations over the period were less than 2% and no payouts would exceed 150% of target award. These threshold, target and maximum payout levels were consistent with the earnings growth guidance provided publicly by management at the time of the grants.

For the three-year performance period 2004-2006, our average growth in EPS from ongoing operations fell below the 2% threshold which resulted in no payouts.

Retirement and Other Benefit Plans

We currently sponsor the following retirement benefit plans:

•: a tax qualified defined benefit retirement plan (the "Retirement Plan");
•: a non-tax qualified defined benefit Supplemental Executive Retirement Plan (the "SERP") for our senior executive officers;
•: a tax qualified defined contribution plan (the "401(k) Plan"); and
•: a non-tax qualified defined contribution Executive Deferred Compensation Plan (the "EDCP") for our senior executive officers.

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

The SERP and the EDCP plans 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 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 executive officers, including the Named Executive Officers, are participants in the SERP and/or EDCP. The SERP and the EDCP are described under the caption "Potential Payments Upon Termination or Change in Control — Retirement Benefits" on page 45 of this proxy statement. We provide the SERP and 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 are necessary to make our senior executive officer retirement benefits competitive.

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 certain of our executive officers with additional long-term disability insurance and term life insurance.

Termination, Severance and Change in Control Arrangements

We have entered into arrangements with certain of our senior executive officers, including our Named Executive Officers, that provide for payments to them 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." These arrangements are not uncommon for executives at the level of our Named Executive Officers, including executives of the companies included in our compensation market survey information, and are generally expected by those holding such positions. We believe these arrangements are an important factor 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 a number of perquisites to senior executive officers as summarized below.

Company Aircraft

The Company maintains 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 and financial groups, principally in Washington, D. C. and New York, New York. Our senior executive officers may use our aircraft for business purposes on a non-exclusive basis. Our aircraft may also be used from time to time 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 very 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 2006 compensation, we valued the aggregate incremental cost of the personal use of our aircraft 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. Items included in our aggregate incremental cost are as follows: aircraft fuel and oil expenses per hour of flight; crew salaries; maintenance, parts and external labor (inspections and repairs) per hour of flight; aircraft accrual expenses per hour of flight; landing/parking/flight planning services expenses; crew travel expenses; and supplies and catering.

Medical Examinations

We 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. We believe this examination helps encourage health-conscious senior executive officers, and helps us plan for any health related retirements or resignations.

Security Systems

We offer free 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 multiple homes 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 initiation fees and monthly dues for one dining club membership for each senior executive officer for business use. We allow 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. Some of our meetings are at resort locations where resort amenities may be provided.

Accounting and Tax Treatments of Compensation

Deductibility of Executive Compensation

Section 162(m) of the Internal Revenue Code establishes a limit on the 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 deduction limit. Our Long-Term Equity Compensation Plan is qualified so that most performance-based awards under that plan constitute compensation that is not subject to Section 162(m). Our Short-Term Incentive Plan does not meet 162(m) deductibility requirements. To maintain flexibility in compensating senior executive officers in a manner designed to promote various corporate goals, the Human Resources Committee has not adopted a policy that all compensation must be deductible. Since Mr. Timmerman's salary is above the $1,000,000 threshold, we may not deduct a portion of his compensation. The Human Resources Committee considered these tax and accounting effects in connection with its deliberations on senior executive compensation.

Nonqualified Deferred Compensation

On January 1, 2005, the Internal Revenue Code was amended to include a new Section 409A, which would impose interest and penalties on receipt of certain types of deferred compensation payments. Deferred compensation plans are required to be amended to comply with the requirements of Section 409A, if necessary, by the end of 2007 to avoid imposition of such interest and penalties. In the meantime, the plans must operate in good faith compliance with

Section 409A, and we believe our deferred compensation plans meet this requirement. We have determined that amendments will be required to the Supplemental Executive Retirement Plan, the Executive Deferred Compensation Plan, the Key Executive Severance Benefits Plan and the Supplementary Key Executive Severance Benefits Plan to cause these plans to comply with Section 409A. The Human Resources Committee expects to address these amendments in 2007.

Accounting for Stock Based Compensation

Beginning January 1, 2006, we began accounting for stock based compensation in accordance with the requirements of Statement of Financial Accounting Standards No. 123(R).

Compensation for 2007

On February 15, 2007, the Board, on the recommendation of the Human Resources Committee, adopted criteria for performance awards for the 2007 - 2009 performance cycle under the Long-Term Equity Compensation Plan. These criteria are discussed under "—Long-Term Equity Compensation Plan — Performance Share Awards."

On the same day, upon recommendation of the Human Resources Committee, the Board approved base salaries for our Named Executive Officers and criteria for performance awards under our Short-Term Annual Incentive Plan for the year 2007. Such base salaries and performance award criteria do not differ materially from year 2006 levels.

As noted above, in 2007, the Human Resources Committee expects to make amendments to our deferred compensation plans as necessary to address issues raised by Internal Revenue Code Section 409A.

Financial Restatement

Although we have never experienced such a situation, our Board of Directors' policy is 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

We do not currently have any equity or other security ownership guidelines or requirements for executive officers (specifying applicable amounts and forms of ownership), or any policies regarding hedging the economic risk of such ownership. However, all of our senior executive officers have a significant amount of their 401(k) plan accounts invested in SCANA stock.

Compensation Committee Report

The Human Resources Committee has reviewed and discussed with management the "Compensation Discussion and Analysis" included in this proxy statement. Based on that review and discussion, the Human Resources 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, 2006 for filing with the Securities and Exchange Commission and in this proxy statement.

Mr. G. Smedes York (Chairman)
Mr. James A. Bennett
Mr. William C. Burkhardt
Mrs. Sharon A. Decker
Mr. D. Maybank Hagood
Ms. Lynne M. Miller
Mr. Maceo K. Sloan

SUMMARY COMPENSATION TABLE

The following table summarizes information about compensation paid or accrued during 2006 to our Chief Executive Officer, our Chief Financial Officer and former 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	Year		Salary ($)		Bonus ($)⁽¹⁾		Stock Awards ($)⁽²⁾		Option Awards ($)		Non-Equity Incentive Plan Compensation ($)⁽³⁾		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)⁽⁴⁾		All Other Compensation ($)⁽⁵⁾		Total ($)
(a)	(b)		(c)		(d)		(e)		(f)		(g)		(h)		(i)		(j)

W. B. Timmerman, President and Chief Executive Officer	2006	$	1,002,700	$	170,459	$	(1,398,181	)	0	$	426,148	$	274,724	$	73,629	$	549,479

J. E. Addison, Senior Vice President Chief Financial Officer⁽⁶⁾	2006	$	278,990	$	27,916	$	(156,699	)	0	$	69,789	$	21,981	$	30,091	$	272,068

K. B. Marsh, President and Chief Operating Officer of SCE&G⁽⁷⁾	2006	$	516,183	$	66,916	$	(478,476	)	0	$	167,290	$	59,934	$	63,816	$	395,663

F. P. Mood, Jr., Senior Vice President and General Counsel	2006	$	350,000	$	35,000	$	27,075	⁽⁸⁾	0	$	87,500	$	59,582	$	41,051	$	600,208

G. J. Bullwinkel, Jr., Senior Vice President	2006	$	425,000	$	51,000	$	(344,667	)	0	$	127,500	$	83,324	$	49,655	$	391,812

S. A. Byrne, Senior Vice President	2006	$	400,400	$	48,048	$	(346,911	)	0	$	120,120	$	40,226	$	45,550	$	307,433

(1): Discretionary bonus awards as permitted under the 2006 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 25.
(2): The information in this column relates to performance share awards (liability awards) under the Long-Term Equity Compensation Plan. This plan is discussed under "—Compensation Discussion and Analysis — Long-Term Equity Compensation Plan — 2006 Long-Term Incentive Plan Awards." The assumptions made in valuation of stock awards are set forth in Note 3 to our audited financial statements for the year ended December 31, 2006, which are included in our 2006 Form 10-K and with this proxy statement.
: As explained below, the amounts in this column do not represent deductions from compensation actually paid to our Named Executive Officers, or repayments by them of previously awarded compensation. Rather, this column reflects the aggregate amounts we recorded as (negative) compensation expense in the income statement and amounts which were (credited to) capitalized costs in our financial statements for the year ended December 31, 2006, for all three performance plan cycles which were in operation during the year. As such, the amounts reported include not only compensation cost recognized with respect to awards granted in 2006 for the 2006-2008 plan cycle, but also reductions of accruals in prior years of compensation cost related to awards granted in 2004 for the 2004-2006 plan cycle and in 2005 for the 2005-2007 plan cycle.
: During 2006, our EPS from ongoing operations did not grow, and TSR performance lagged our peer group. As such, awards for the 2004-2006 plan cycle, for which significant amounts had been accrued in prior years, fell below performance threshold payout levels, with requisite reductions of prior accruals being recorded in 2006. Similarly, prior accruals related to the 2005-2007 plan cycle were reduced in 2006 based on this decline in relative TSR and lower earnings growth performance. These reductions of prior compensation cost accruals were only partially offset by accruals related to the 2006-2008 plan cycle, which accruals were also limited by the 2006 TSR and EPS from ongoing operations performance.
(3): Payouts under the 2006 Short-Term Annual Incentive Plan, based on our achieving our business objectives and our Named Executive Officers achieving their individual financial and strategic objectives, as discussed in further detail under "—Compensation Discussion and Analysis — Short-Term Annual Incentive Plan" on page 22.
(4): 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 December 31, 2005 to December 31, 2006, 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" on page 28.

(5): All other compensation paid to each Named Executive Officer, including company contributions to the 401(k) Plan and the Executive Deferred Compensation Plan, tax reimbursements with respect to perquisites or other personal benefits, and life insurance premiums on policies owned by Named Executive Officers. For 2006, the Company contributions to defined contribution plans were as follows: Mr. Timmerman — $66,420; Mr. Addison — $26,306; Mr. Marsh — $60,044; Mr. Mood — $36,750; Mr. Bullwinkel — $44,625; and Mr. Byrne — $42,042. For 2006, tax reimbursements with respect to perquisites or other personal benefits were as follows: Mr. Timmerman — $1,463; Mr. Addison — $716; Mr. Marsh — $133; Mr. Mood — $205; Mr. Bullwinkel — $0; and Mr. Byrne — $442. Neither life insurance premiums on policies owned by the Named Executive Officers nor perquisites exceeded $10,000 for any Named Executive Officer.
(6): Mr. Addison was appointed as our Chief Financial Officer in April, 2006.
(7): Mr. Marsh served as our Chief Financial Officer until April, 2006, at which time he was appointed as the President and Chief Operating Officer of SCE&G.
(8): Mr. Mood did not participate in the 2004-2006 or 2005-2007 cycles of the Long-Term Equity Compensation Plan and, therefore, no accruals under these cycles had to be reversed with respect to him. The amount shown for Mr. Mood represents the accruals related to the award under the 2006-2008 cycle as discussed under footnote 2 above.

2006 GRANTS OF PLAN-BASED AWARDS

The following table sets forth each grant of an award made to a Named Executive Officer under our compensation plans during 2006.

			Estimated Possible Payouts Under Non-Equity Incentive Plan Awards⁽¹⁾									Estimated Future Payouts Under Equity Incentive Plan Awards⁽²⁾


Name	Grant Date			Threshold ($)			Target ($)			Maximum ($)		Threshold (#)		Target (#)		Maximum (#)		All Other Stock Awards: Number of Shares of Stock or Units (#)		All Other Option Awards: Number of Securities Underlying Options (#)		Exercise or Base Price of Option Awards ($/Sh)		Grant Date Fair Value of Stock and Option Awards
(a)	(b	)		(c	)		(d	)		(e	)	(f	)	(g	)	(h	)	(i	)	(j	)	(k	)	(l	)

W. B. Timmerman	2-16-06 2-16-06		$	426,148		$	852,295		$	1,278,443		35,044		70,088		105,132

J. E. Addison	2-16-06 2-16-06		$	69,789		$	139,578		$	209,367		4,356		8,711		13,067

K. B. Marsh	2-16-06 2-16-06		$	167,290		$	334,580		$	501,870		12,397		24,794		37,191

F. P. Mood, Jr.	2-16-06 2-16-06		$	87,500		$	175,000		$	262,500		5,811		11,621		17,432

G. J. Bullwinkel, Jr.	2-16-06 2-16-06		$	127,500		$	255,000		$	382,500		8,170		16,339		24,509

S. A. Byrne	2-16-06 2-16-06		$	120,120		$	240,240		$	360,360		7,697		15,393		23,090

(1): The amounts in columns (c), (d) and (e) represent the threshold, target and maximum awards that could have been paid under the 2006 Short-Term Annual Incentive Plan if performance criteria were met. Performance criteria were met only at the threshold level, and therefore, as reflected in the "Non-Equity Incentive Plan Compensation" column of the Summary Compensation Table, the amounts paid were those shown in column (c). A discussion of the 2006 Short-Term Annual Incentive Plan is included under "—Compensation Discussion and Analysis — Short-Term Annual Incentive Plan" on page 22. See also, "—Compensation Discussion and Analysis—Short-Term Annual Incentive Plan — Discretionary Bonus Award" on page 25 for a discussion of the discretionary bonus paid under this plan.
(2): Represents potential future payouts of the 2006-2008 cycle of performance share awards under the Long-Term Equity Compensation Plan. Payout of performance share awards will be dictated by our performance against pre-determined measures of TSR and growth in EPS from ongoing operations over the three year plan cycle. A discussion of the components of the performance share awards is included under "—Compensation Discussion and Analysis — Long-Term Equity Compensation Plan — Performance Share Awards" on page 25.

OUTSTANDING EQUITY AWARDS AT 2006 FISCAL YEAR-END

The following table sets forth certain information regarding unexercised options and equity incentive plan awards for each Named Executive Officer outstanding as of December 31, 2006.


	Option Awards						Stock Awards

Name	Number of Securities Underlying Unexercised Options (#) Exercisable⁽¹⁾	Number of Securities Underlying Unexercised Options (#) Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)		Option Exercise Price ($)	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)	Market Value of Shares or Units of Stock That Have Not Vested ($)	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)⁽²⁾⁽⁴⁾		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)⁽³⁾⁽⁴⁾
(a)	(b)	(c)	(d)		(e)	(f)	(g)	(h)	(i)		(j)

W. B. Timmerman	123,067			$	27.52	02/21/2012
									99,153	$	4,027,595

J. E. Addison									10,157	$	412,577

K. B. Marsh									32,968	$	1,339,160

F. P. Mood, Jr.									14,692	$	596,789

G. J. Bullwinkel, Jr.	2,938			$	27.45	02/22/2011
	33,724			$	27.52	02/21/2012
	8,617			$	29.60	08/01/2012
									20,461	$	831,126

S. A. Byrne	21,492			$	27.52	02/21/2012
									19,276	$	782,991

(1): The vesting date of Mr. Byrne's options was February 21, 2005. All other options were exercised after December 31, 2006.
(2): Assuming the performance criteria are met, the vesting dates of these awards would be as follows: Mr. Timmerman — 50,091 shares would vest on December 31, 2007 and 49,062 shares would vest on December 31, 2008; Mr. Addison — 4,059 shares would vest on December 31, 2007 and 6,098 shares would vest on December 31, 2008; Mr. Marsh — 15,612 shares would vest on December 31, 2007 and 17,356 shares would vest on December 31, 2008; Mr. Mood — 6,557 shares would vest on December 31, 2007 and 8,135 shares would vest on December 31, 2008; Mr. Bullwinkel — 9,023 shares would vest on December 31, 2007 and 11,438 shares would vest on December 31, 2008; and Mr. Byrne — 8,501 shares would vest on December 31, 2007 and 10,775 shares would vest on December 31, 2008.
(3): 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 29, 2006 of $40.62.
(4): For the 2004-2006 plan cycle, no shares vested or were earned because performance criteria were not met. For the 2005-2007 cycle, performance shares tracking against TSR (60% of target shares) are projected to result in zero payout. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the threshold performance measure for the TSR portion of the shares. Performance shares tracking against growth in EPS from ongoing operations (40% of target shares) for the 2005-2007 performance cycle are projected to result in a payout between threshold and target. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the target performance measure for the growth in EPS from ongoing operations portion of the shares. For the 2006-2008 cycle, performance shares tracking against TSR (60% of target shares) are projected to result in zero payout. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the threshold performance measure for the TSR portion of the shares. Performance shares tracking against growth in EPS from ongoing operations (40% of target shares) for the 2006-2008 performance cycle are projected to result in a payout between threshold and target. Therefore, the number of shares and payout value shown in columns (i) and (j) are based on the target performance measure for the growth in EPS from ongoing operations portion of the shares.

2006 OPTION EXERCISES AND STOCK VESTED

The following table sets forth information about exercises of stock options for each Named Executive Officer during 2006. No stock awards vested in 2006.


	Option Awards			Stock Awards

Name	Number of Shares Acquired on Exercise (#)		Value Realized on Exercise ($)	Number of Shares Acquired on Vesting (#)	Value Realized on Vesting ($)
(a)	(b)		(c)	(d)	(e)

W. B. Timmerman

J. E. Addison

K. B. Marsh

F. P. Mood, Jr.

G. J. Bullwinkel, Jr.

S. A. Byrne	21,500	$	268,286

PENSION BENEFITS

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


Name	Plan Name	Number of Years Credited Service (#)⁽¹⁾		Present Value of Accumulated Benefit ($)⁽¹⁾⁽²⁾	Payments During Last Fiscal Year($)
(a)	(b)	(c)		(d)	(e)

W. B. Timmerman	SCANA Retirement Plan SCANA Supplemental Executive Retirement Plan	28 28	$ $	792,631 2,090,423	0 0

J. E. Addison	SCANA Retirement Plan SCANA Supplemental Executive Retirement Plan	15 15	$ $	128,406 68,597	0 0

K. B. Marsh	SCANA Retirement Plan SCANA Supplemental Executive Retirement Plan	22 22	$ $	423,655 369,986	0 0

F. P. Mood, Jr.	SCANA Retirement Plan SCANA Supplemental Executive Retirement Plan	2 2	$ $	35,333 54,862	0 0

G. J. Bullwinkel, Jr.	SCANA Retirement Plan SCANA Supplemental Executive Retirement Plan	35 35	$ $	1,050,471 672,483	0 0

S. A. Byrne	SCANA Retirement Plan SCANA Supplemental Executive Retirement Plan	11 11	$ $	110,324 174,521	0 0

(1): Computed as of December 31, 2006, 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 the end of 2006, 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 3 to our audited financial statements for the year ended December 31, 2006, which are included in our Form 10-K for the year ended December 31, 2006 and with this proxy statement.

The SCANA Retirement Plan and Supplemental Executive Retirement Plan are both cash balance defined benefit plans. The plans provide for full vesting after five years of service or after reaching age 65. All Named Executive Officers are fully vested in both plans.

Defined Benefit 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 and is equal to the average rate for 30-year Treasury Notes 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 our Retirement Plan for all employees, we provide a Supplemental Executive Retirement Plan for certain eligible employees, including the Named Executive Officers. The Supplemental Executive Retirement Plan 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 Supplemental Executive Retirement Plan is discussed under the caption "—Potential Payments Upon Termination or Change in Control — Retirement Benefits" on page 45, and under the caption "—Compensation Discussion and Analysis — Retirement and Other Benefit Plans" on page 28.

2006 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 ($)	Aggregate Withdrawals/ Distributions ($)		Aggregate Balance at Last FYE ($)
(a)		(b)		(c)		(d)	(e)		(f)

W. B. Timmerman	$	53,220	$	53,220	$	155,692	0	$	2,652,609

J. E. Addison	$	13,572	$	13,387	$	19,862	0	$	325,102

K. B. Marsh	$	46,962	$	46,844	$	143,723	0	$	1,105,338

F. P. Mood, Jr.	$	23,550	$	23,550	$	7,434	0	$	68,533

G. J. Bullwinkel, Jr.	$	245,835	$	31,425	$	84,891	0	$	1,430,237

S. A. Byrne	$	52,877	$	28,842	$	24,551	0	$	439,168

(1): The amounts reported in Columns (b) and (c) are reflected in the Summary Compensation Table.

Executive Deferred Compensation Plan

We have adopted the SCANA Corporation Executive Deferred Compensation Plan, in which our Named Executive Officers may participate if they choose to do so. The plan is a non-qualified deferred compensation plan. Each participant may elect to defer up to 25% of that part of his or her eligible earnings (as defined in the 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 2006, participants could defer eligible earnings in excess of $220,000. 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 in excess of the limit amount not including any performance share award.

We record the amount of each participant's deferred compensation and the amount we match in a special ledger. We also credit a rate of return to each participant's special ledger account based on hypothetical investment alternatives chosen by the participant. The committee that administers the Executive Deferred Compensation Plan 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 special 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 special ledger account is reduced by the corresponding amount. All amounts credited to a participant's special 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 beneficiary. No actual investments are made. The investment alternatives are only used to generate a rate of increase (or decrease) in the special 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 Plan. 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 Plan. 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.

In 2006, the Named Executive Officers' special ledger accounts were credited with earnings (or losses) based on the following investment alternatives and rates of returns:

INVESCO Stable Value Trust (4.30%); PIMCO Total Return (3.74%); Dodge & Cox Common Stock (18.53%); American Century Inc. & Growth Adv. (16.86%); INVESCO 500 Index Trust (15.37%); Pioneer Oak Ridge Large Cap Growth (2.61%); T. Rowe Price Mid Cap Value (20.24%); Lord Abbett Growth Opportunity (7.66%); RS Partners (11.22%); Vanguard Explorer (9.88%); American Funds Europacific Growth (21.87%); SCANA Corporation Stock (7.60%); Janus Small Cap Value (12.4%); Vanguard Target Retirement Income (6.38%); Vanguard Target Retirement 2005 (8.23%); Vanguard Target Retirement 2015 (11.42%); Vanguard Target Retirement 2025 (13.24%); Vanguard Target Retirement 2035 (15.24%); Vanguard Target Retirement 2045 (15.98%). 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.

All amounts deferred under the Executive Deferred Compensation Plan, matching contributions and earnings credited to a participant's special ledger account are paid, or begin to be paid, to the participant either in a lump sum or installments for up to 15 years at a later time chosen by the participant; provided, however, that the deferred amounts are to be paid, or to begin to be paid, as soon as practicable following the participant's death, disability, retirement or other termination of employment.

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 special ledger account due to severe financial hardship as the result of extraordinary and unforeseeable circumstances arising as a result of events beyond the individual's control. With respect to amounts earned and vested before January 1, 2005, a participant may also obtain payment of his special ledger account on an accelerated basis by forfeiting 10% of the amount accelerated or by making the election to accelerate the payment not less than 12 months before the payment will 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."

We plan to amend all available distribution and withdrawal options with respect to amounts earned or vested after 2004 to conform to the new requirements for deferred compensation under Section 409A of the Internal Revenue Code. The Internal Revenue Service has issued proposed and preliminary guidance under Section 409A, but the extent of any changes needed to conform the plan to Section 409A will not be clear until after final guidance is issued. Currently, the Internal Revenue Service requires that changes to conform to Section 409A generally be made by December 31, 2007. However, we were required to operate in good faith compliance from January 1, 2005 forward, subject to guidance issued by the Internal Revenue Service.

Potential Payments Upon Termination or Change in Control

Change in Control Arrangements

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

We have adopted the SCANA Corporation Key Executive Severance Benefits Plan and the SCANA Corporation Supplementary Key Executive Severance Benefits Plan, which provide for payments to our senior executive officers in connection with a change in control of our Company. The Key Executive Severance Benefits Plan (the "Severance Plan") provides for payment of benefits in a lump sum immediately upon a change in control unless the plan has been terminated prior to the change in control. This plan is designed to provide for benefits in the event of a change in control that our Board deems to be hostile. In the event of a change in control that our Board deems to be friendly, we anticipate that the Board would terminate the Severance Plan prior to the change in control. If the Severance Plan is terminated, the Supplementary Key Executive Severance Benefits Plan (the "Supplementary Severance Plan") would provide for payment of benefits if, within 24 months after the 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.

Both plans provide 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 (a) were directors on the Board at the beginning of such period, or (b) 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 our shareholders approve (a) 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), (b) a plan of complete liquidation of our Company, or (c) an agreement to sell or dispose of all or substantially all of our assets; or
•: if our shareholders approve a plan of complete liquidation, or sale or disposition 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.)

As noted above, benefits under the Supplementary Severance Plan would be triggered if we terminated the Severance Plan prior to a change in control, and, within 24 months after the 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 perform his or her duties after we made demand for substantial performance;
•: willfully engaged in conduct that is 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:

•: he or she were assigned to duties inconsistent with his or her duties, or had a reduction or alteration in the nature or status of his or her responsibilities, from those in effect 90 days prior to the change in control;
•: we reduced his or her base salary as in effect 30 days prior to the occurrence of certain preliminary actions preceding the change in control (such as the execution of agreements relating to a change in control, public announcements by us of our intentions, transfers of securities representing at least 8¹/2% of our stock or the adoption of board resolutions with respect thereto);
•: after the change in control, we required him or her to be based more than 25 miles from his or her location as of the effective date of the Supplementary Severance Plan;
•: we failed to continue to offer any annual or long-term incentive programs for officers which were in effect on the effective date of the change in control, or other employee benefit plans, policies, practices or arrangements in which he or she participates, unless similar plans of equal value are put in place, or we failed to permit him or her to continue participation on substantially the same basis as existed on the date of the change in control;
•: we failed to obtain a satisfactory agreement from any successor to assume and perform the Supplementary Severance Plan; or
•: we purported to terminate him or her without using a notice of termination that satisfies the requirements of the Supplementary Severance Plan.

Potential Benefits Payable

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

•: An amount intended to approximate three times the sum of: (i) his or her annual base salary (before reduction for certain pre-tax deferrals) and (ii) his or her full targeted annual incentive award, in each case as in effect for the year in which the change in control occurs;
•: 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 Supplemental Executive Retirement Plan, determined prior to any offset for amounts payable under the SCANA 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 SCANA Retirement Plan; 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, immediately upon a change in control prior to which we had not terminated the Severance Plan (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 of all amounts credited to his or her Executive Deferred Compensation Plan ledger account as of the date of the change in control;
•: A benefit distribution under the Long-Term Equity Compensation Plan equal to 100% of the target performance share award for all performance periods not completed as of the date of the change in control, if any;
•: A benefit distribution under the Short-Term Annual Incentive Plan equal to 100% of the target award in effect as of the date of the change in control;
•: Under the Long-Term Equity Compensation Plan and related agreements, all nonqualified stock options awarded and non-vested target performance shares would become immediately exercisable or vested and remain exercisable throughout their original term or, in the case of performance shares, vested and payable within 30 days of the change in control; and
•: Any amounts previously earned, but not yet paid, under the terms of any of our other plans or programs.

Under the Supplementary Severance Plan, senior executive officers would also be entitled to all of the benefits described above. In addition, interest would be paid on the benefits payable under the Executive Deferred Compensation Plan 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 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. Any amounts payable under the Supplementary Severance Plan would be reduced by all amounts, if any, received under the Severance Plan.

In addition, benefit distributions to senior executive officers under either the Severance Plan or the Supplementary Severance Plan would also include payment of an amount (a "gross-up payment") reimbursing him or her for the amount of anticipated excise tax imposed under Section 4999 of the Internal Revenue Code (or any similar tax) on such benefits and the gross-up payment, and any income and employment tax and excise tax due with respect to the gross-up payment.

Calculation of Benefits Potentially Payable to our Named Executive Officers if a Triggering Event had Occurred as of December 29, 2006

Severance Plan

If we had been subject to a change in control as of December 29, 2006, and the Severance Plan had not been terminated, our Named Executive Officers would have been immediately entitled to the benefits outlined below.

Mr. Timmerman would have been entitled to the following: an amount equal to three times his base salary and target short-term incentive award — $5,565,000; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above — $812,000; an amount equal to insurance continuation benefits for three years — $34,000; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan — $5,754,000; and anticipated excise tax and gross-up payment — $5,290,000. The total value of these change in control benefits would have been $17,455,000. In addition, Mr. Timmerman would have been paid amounts previously earned, but not yet

paid, as follows: 2006 actual short-term annual incentive award — $596,607; Executive Deferred Compensation Plan account balance — $2,652,609; Supplemental Executive Retirement Plan and Retirement Plan account balances — $3,056,000; vacation accrual — $69,000; as well as his 401(k) Plan account balance.

Mr. Addison would have been entitled to the following: an amount equal to three times his base salary and target short-term incentive award — $1,274,000; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above — $545,000; an amount equal to insurance continuation benefits for three years — $61,000; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan — $589,000; and anticipated excise tax and gross-up payment — $1,087,000. The total value of these change in control benefits would have been $3,556,000. In addition, Mr. Addison would have been paid amounts previously earned, but not yet paid, as follows: 2006 actual short-term annual incentive award — $97,705; Executive Deferred Compensation Plan account balance — $325,102; Supplemental Executive Retirement Plan and Retirement Plan account balances — $246,000; vacation accrual — $9,000; as well as his 401(k) Plan account balance.

Mr. Marsh would have been entitled to the following: an amount equal to three times his base salary and target short-term incentive award — $2,579,000; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above — $905,000; an amount equal to insurance continuation benefits for three years — $46,000; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan — $1,913,000; and anticipated excise tax and gross-up payment — $2,296,000. The total value of these change in control benefits would have been $7,739,000. In addition, Mr. Marsh would have been paid amounts previously earned, but not yet paid, as follows: 2006 actual short-term annual incentive award — $234,206; Executive Deferred Compensation Plan account balance — $1,105,338; Supplemental Executive Retirement Plan and Retirement Plan account balances — $934,000; vacation accrual — $9,000; as well as his 401(k) Plan account balance.

Mr. Mood would have been entitled to the following: an amount equal to three times his base salary and target short-term incentive award — $1,575,000; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above — $0; an amount equal to insurance continuation benefits for three years — $35,000; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan — $853,000; and anticipated excise tax and gross-up payment — $1,090,000. The total value of these change in control benefits would have been $3,553,000. In addition, Mr. Mood would have been paid amounts previously earned, but not yet paid, as follows: 2006 actual short-term annual incentive award — $122,500; Executive Deferred Compensation Plan account balance — $68,533; Supplemental Executive Retirement Plan and Retirement Plan account balances — $90,000; vacation accrual — $0; as well as his 401(k) Plan account balance.

Mr. Bullwinkel would have been entitled to the following: an amount equal to three times his base salary and target short-term incentive award — $2,040,000; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above — $380,000; an amount equal to insurance continuation benefits for three years — $44,000; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan — $1,187,000; and

anticipated excise tax and gross-up payment — $1,581,000. The total value of these change in control benefits would have been $5,232,000. In addition, Mr. Bullwinkel would have been paid amounts previously earned, but not yet paid, as follows: 2006 actual short-term annual incentive award — $178,500; Executive Deferred Compensation Plan account balance — $1,430,237; Supplemental Executive Retirement Plan and Retirement Plan account balances — $1,867,000; vacation accrual — $22,000; as well as his 401(k) Plan account balance.

Mr. Byrne would have been entitled to the following: an amount equal to three times his base salary and target short-term incentive award — $1,922,000; an amount equal to the excess payable under the Supplemental Executive Retirement Plan as calculated under the assumptions described above — $807,000; an amount equal to insurance continuation benefits for three years — $63,000; an amount equal to the value of 100% of his target performance shares under the Long-Term Equity Compensation Plan — $1,119,000; and anticipated excise tax and gross-up payment — $1,716,000. The total value of these change in control benefits would have been $5,627,000. In addition, Mr. Byrne would have been paid amounts previously earned, but not yet paid, as follows: 2006 actual short-term annual incentive award — $168,168; Executive Deferred Compensation Plan account balance — $439,168; Supplemental Executive Retirement Plan and Retirement Plan account balances — $353,000; vacation accrual — $17,000; as well as his 401(k) Plan account balance.

In addition to the foregoing benefits, all option and stock awards set forth in the "2006 Outstanding Equity Awards at Fiscal Year-End" table would have vested for each Named Executive Officer.

Supplementary Severance Plan

If (i) we had been subject to a change in control in the past 24 months, (ii) the Severance Plan had been terminated prior to the change in control, and (iii) as of December 29, 2006, 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 above, together with an amount equal to an increase in the amount payable with respect to his Executive Deferred Compensation Plan account, calculated as outlined above. The actual amount of any such additional payment would depend upon the date on which employment of the Named Executive Officer terminated subsequent to the change in control.

Retirement Benefits

Supplemental Executive Retirement Plan

The SCANA Corporation Supplemental Executive Retirement Plan (the "SERP") is an unfunded nonqualified deferred compensation 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

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 Severance Plan and the Supplementary Severance Plan. See the discussion under "Change in Control Arrangements."

Unless otherwise provided in a participant agreement, the amount of any benefit payable to a participant under the SERP will be determined as of the date he or she first becomes eligible to receive benefits under the SERP, and will be equal to (i) the cash balance account that otherwise would have been payable under the Retirement Plan as of such determination date, based on compensation and disregarding the limitations imposed by the Internal Revenue Code on the amount of annual retirement benefits payable to employees from qualified pension plans and on the amount of annual compensation that may be taken into account for all qualified plan purposes, minus (ii) the participant's cash balance account determined under the Retirement Plan as of such 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. With respect to amounts earned and vested before January 1, 2005, the participant may elect, in accordance with procedures we establish, to receive a distribution of such benefit in either of the following two forms of payment:

•: A single sum distribution of the value of the participant's benefit under the SERP determined as of the last day of the month preceding the date he or she first becomes eligible to receive benefits; or
•: 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 first day of the month following the date on which he or she first becomes eligible to receive benefits. 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.

For amounts earned and vested after January 1, 2005, the amounts are subject to Internal Revenue Service Code Section 409A and the choice between lump sum and annuity is not available. The new distribution options have not yet been determined.

Unless otherwise provided in a participant agreement, if a participant dies before the first day of the calendar month after he or she becomes eligible to receive benefits under the SERP, a single sum distribution equal to the value of the 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. With respect to SERP amounts earned and vested on or after January 1, 2005, the available distribution options will be limited in accordance with Section 409A of the Internal Revenue Code.

Calculation of Benefits Potentially Payable to our Named Executive Officers if a Triggering Event had Occurred as of December 29, 2006

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 29, 2006 are set forth below.

Also set forth below are the payments that would be made to each Named Executive Officer's designated beneficiary if the officer had died December 29, 2006.

For Mr. Timmerman, the lump sum amount would have been $2,216,155, or the monthly payments would have been $13,536 for the remainder of his lifetime. In the event he had died December 29, 2006 after becoming eligible for benefits, his designated beneficiary would receive monthly payments of $8,121 for up to 15 years. If Mr. Timmerman had died December 29, 2006 before becoming eligible for benefits, his beneficiary would have been entitled to a lump sum payment equal to the amount shown above.

For Mr. Addison, the lump sum amount would have been $85,796, or the monthly payments would have been $417 for the remainder of his lifetime. In the event he had died December 29, 2006 after becoming eligible for benefits, his designated beneficiary would receive monthly payments of $250 for up to 15 years. If Mr. Addison had died December 29, 2006 before becoming eligible for benefits, his beneficiary would have been entitled to a lump sum payment equal to the amount shown above.

For Mr. Marsh, the lump sum amount would have been $435,636, or the monthly payments would have been $2,264 for the remainder of his lifetime. In the event he had died December 29, 2006 after becoming eligible for benefits, his designated beneficiary would receive monthly payments of $1,359 for up to 15 years. If Mr. Marsh had died December 29, 2006 before becoming eligible for benefits, his beneficiary would have been entitled to a lump sum payment equal to the amount shown above.

For Mr. Mood, the lump sum amount would have been $54,862, or the monthly payments would have been $420 for the remainder of his lifetime. In the event he had died December 29, 2006 after becoming eligible for benefits, his designated beneficiary would receive monthly payments of $252 for up to 15 years. If Mr. Mood had died December 29, 2006 before becoming eligible for benefits, his beneficiary would have been entitled to a lump sum payment equal to the amount shown above.

For Mr. Bullwinkel, the lump sum amount would have been $728,627, or the monthly payments would have been $4,280 for the remainder of his lifetime. In the event he had died December 29, 2006 after becoming eligible for benefits, his designated beneficiary would receive monthly payments of $2,568 for up to 15 years. If Mr. Bullwinkel had died December 29, 2006 before becoming eligible for benefits, his beneficiary would have been entitled to a lump sum payment equal to the amount shown above.

For Mr. Byrne, the lump sum amount would have been $216,129, or the monthly payments would have been $1,062 for the remainder of his lifetime. In the event he had died

December 29, 2006 after becoming eligible for benefits, his designated beneficiary would receive monthly payments of $637 for up to 15 years. If Mr. Byrne had died December 29, 2006 before becoming eligible for benefits, his beneficiary would have been entitled to a lump sum payment equal to the amount shown above.

Executive Deferred Compensation Plan

The SCANA Corporation Executive Deferred Compensation Plan is described in the narrative following the 2006 Nonqualified Deferred Compensation table on page 39. As discussed in that section, amounts deferred under the plan are required to be paid, or begin to be paid, as soon as practicable following a participant's death, disability, retirement or other termination of employment. Such payments are made in the form of a single sum cash distribution. However, at the election of the participant, payments payable after the participant's death after reaching retirement age, retirement, or termination of employment as a result of disability, may be made in the form of annual installment payments over a period not to exceed 15 years. The plan defines "retirement age" as the later of reaching age 55 and 20 years of vesting service or attainment of age 65, and defines "retirement" as termination of employment after reaching retirement age. All amounts credited to a participant's special 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 terms of the plan governing distributions and deferrals are subject to further modification to conform to the requirements of Section 409A of the Internal Revenue Code.

The "Aggregate Balance at Last FYE" column of the 2006 Nonqualified Deferred Compensation table shows the amounts that would have been payable under the Executive Deferred Compensation Plan to each of our Named Executive Officers if they had died after reaching retirement age, retired, or if their employment had been terminated as a result of disability, as of December 29, 2006, and 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 installment payments over the payment periods selected by the Named Executive Officers are estimated as set forth below: Mr. Timmerman — $530,522; Mr. Addison — $65,020; Mr. Marsh — $221,068; Mr. Mood — $13,707; Mr. Bullwinkel — $286,047; and Mr. Byrne — $87,834.

DIRECTOR COMPENSATION

Board Fees

Our Board reviews director compensation every year with guidance from the Nominating 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 risk inherent in board service. Every other year the Nominating Committee considers relevant public data in making recommendations.

Officers who are also directors do not receive additional compensation for their service as directors. Effective January 1, 2005, compensation for non-employee directors consists of the following:

•: an annual retainer of $45,000 (required to be paid in shares of our common stock effective January 1, 2006);
•: a fee of $6,500 for attendance at regular quarterly meetings of the Board of Directors;
•: a fee of $6,000 for attendance at all-day meetings of the Board of Directors other than regular meetings;
•: a fee of $3,000 for attendance at half-day meetings of the Board of Directors other than regular meetings;
•: a fee of $3,000 for attendance at a committee meeting held on a day other than a day a regular meeting of the Board of Directors is held;
•: a fee of $300 for telephonic meetings of the Board of Directors or a committee that last fewer than 30 minutes;
•: a fee of $600 for telephonic meetings of the Board of Directors or a committee that last more than 30 minutes; and
•: reimbursement of reasonable expenses incurred in connection with all of the above.

Unless deferred at the director's election pursuant to the terms of our Director Compensation and Deferral Plan, directors' retainer fees are paid annually in shares of our common stock, and meeting attendance and conference fees are paid at such times as the Board determines in cash or common stock at the director's election.

Director Compensation and Deferral Plans

Since January 1, 2001, non-employee director compensation and related deferrals have been governed by the SCANA Director Compensation and Deferral Plans. Amounts deferred by directors in previous years under the SCANA Voluntary Deferral Plan continue to be governed by that plan. During 2006, the only director with funds remaining in the Voluntary Deferral Plan was Mr. Bennett.

Under the Director Compensation and Deferral Plan, a director may make an annual irrevocable election to defer the annual retainer fee, which (effective January 1, 2006) is required to be paid in our common stock, in a hypothetical investment in our common stock, with distribution from the plan to be ultimately payable in actual shares of our common stock. A director also may elect to defer up to 100% of meeting attendance and conference fees with distribution from the plan to be ultimately payable in either our common stock or cash. Amounts payable in our common stock accrue earnings during the deferral period at our dividend rate, which directors may choose to have paid in cash when accrued or retained to invest in additional hypothetical shares of our common stock. Amounts payable in cash

accrue interest until paid. Hypothetical shares do not have voting rights.

During 2006, Messrs. Amick, Bennett, Burkhardt, Sloan, York and Ms. Miller elected to defer 100% of their compensation and earnings and Messrs. Hagood and Stowe deferred a portion of their earnings under the Director Compensation and Deferral Plan.

As previously discussed, we plan to amend all available distribution and withdrawal options with respect to amounts earned or vested after 2004 under all of our deferred compensation plans to conform to the requirements for deferred compensation under Section 409A of the Internal Revenue Code.

Endowment Plan

Upon election to a second term, a director becomes 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 is 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, 2006, our obligation under the plan was $4,462,356. The plan is funded through insurance policies on the lives of the directors. The 2006 premium for such insurance was $333,928 which was offset by the receipt of insurance proceeds in the amount of $754,498. The insurance proceeds were received in 2006 after the death of a director in 2005. Currently the premium estimate for 2007 is $95,000.

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

2006 DIRECTOR COMPENSATION

The following table sets forth the compensation we paid to each of our non-employee directors in 2006.


Name		Fees Earned or Paid in Cash ($)		Stock Awards ($)⁽¹⁾	Option Awards ($)	Non-Equity Incentive Plan Compensation ($)		Change in Pension Value and Nonqualified Deferred Compensation Earnings⁽²⁾ ($)	All Other Compensation ($)		Total ($)
(a)		(b)		(c)	(d)	(e)		(f)	(g)		(h)

B. L. Amick	$	43,500	$	45,000						$	88,500

J. A. Bennett	$	71,000	$	45,000			$	3,830		$	119,830

W. C. Burkhardt	$	75,800	$	45,000						$	120,800

S. A. Decker	$	77,600	$	45,000						$	122,600

D. M. Hagood	$	73,400	$	45,000						$	118,400

W. H. Hipp	$	38,000	$	45,000						$	83,000

L. M. Miller	$	81,800	$	45,000						$	126,800

M. K. Sloan	$	76,400	$	45,000						$	121,400

H. C. Stowe	$	57,900	$	45,000						$	102,900

G. S. York	$	68,000	$	45,000						$	113,000

(1): The annual retainer of $45,000 is required to be paid in our common stock. Shares were purchased on January 12, 2006 at a weighted average purchase price of $40.46 in order to satisfy the retainer fee obligation.
(2): Mr. Bennett is the only Director who elected to defer director fees into a cash deferral account. Pursuant to the terms of the deferral plan, the earnings are above market as defined by the rules. The amounts shown above represent Mr. Bennett's above-market earnings on his deferrals into the cash deferral account ($2,404) as well as his earnings on prior cash deferrals into the prior Voluntary Deferral Plan ($1,426).

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.

PERFORMANCE GRAPH

The line graph below compares the cumulative TSR on our common stock, assuming reinvestment of dividends, with the S&P Utilities Index, the S&P 500 Index and a group of peer issuers. We include the peer group index in the performance graph because TSR is measured 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 2006 Peer Group are weighted according to the respective issuer's stock market capitalization at the beginning of each period.

The companies in the 2006 Peer Group index are listed in "Compensation Discussion and Analysis — Long-Term Equity Compensation Plan — 2006 Long-Term Incentive Plan Awards" on page 26.

SCANA Corporation
Comparison of Five-Year Cumulative Total Return*
SCANA Corporation, Long-Term Equity Compensation Plan Peer Groups,
S&P Utilities and S&P 500

* Assumes $100 invested on December 31, 2001, in SCANA common stock, the 2006 Peer Group and the S&P Indices.

AUDIT COMMITTEE REPORT

In connection with the December 31, 2006 financial statements, the Audit Committee (i) reviewed and discussed the audited financial statements with management; (ii) discussed with the independent auditors the matters required to be discussed by the statement on Auditing Standards No. 61, as amended (AICPA, Professional Standards, Vol. 1. AU section 380), as adopted by the Public Company Accounting Oversight Board in Rule 3200T; (iii) received the written disclosures and the letter from the independent accountants required by Independence Standards Board Standard No. 1 (Independence Standards Board Standard No. 1, Independence Discussions With Audit Committees) as adopted by the Public Company Accounting Oversight Board in Rule 3600T; and (iv) has 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, 2006 for filing with the Securities and Exchange Commission.

Mr. Harold C. Stowe (Chairman)
Mr. William C. Burkhardt
Mr. D. Maybank Hagood
Mr. Maceo K. Sloan

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

Deloitte & Touche LLP has served as SCANA's independent registered public accounting firm for the year ended December 31, 2006, and the Audit Committee has appointed Deloitte & Touche LLP to serve as SCANA's independent registered public accounting firm to audit SCANA's 2007 financial statements. Shareholders are being asked to approve this appointment at the Annual Meeting.

The Board of Directors recommends a vote FOR approval of Deloitte & Touche's 2007 appointment.

Unless you indicate to the contrary, the proxy agents 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 SCANA's 2007 financial statements.

Representatives of Deloitte & Touche LLP are expected to be present and available at the Annual Meeting 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

SCANA's 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 to pre-approve the rendering of services by the chairman are presented to the Audit Committee at its next scheduled meeting.

Independent Registered Public Accounting Firm's Fees

The following table sets forth the aggregate fees billed to SCANA and its subsidiaries for the fiscal years ended December 31, 2006 and 2005 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu and their respective affiliates.

	2006		2005
Audit Fees⁽¹⁾	$	2,178,851	$	2,144,848
Audit Related Fees⁽²⁾		118,195		94,082
Tax Fees⁽³⁾		77,820		94,345
All Other Fees		0		0

Total Fees	$	2,374,866	$	2,333,275

(1): Fees for Audit Services billed for 2006 and 2005 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 for 2006 and 2005.
(3): Fees for tax compliance and tax research services.

In 2006 and 2005, all of the Audit Fees, Audit Related Fees and Tax Fees were approved by the Audit Committee.

OTHER INFORMATION

Section 16(a) Beneficial Ownership Reporting Compliance

The rules of the Securities and Exchange Commission require that SCANA disclose late filings of reports of beneficial ownership and changes in beneficial ownership by its directors, executive officers and greater than 10% beneficial owners. To SCANA's knowledge, except as set forth below, based solely on a review of Forms 3, 4 and 5 and amendments to such forms furnished to SCANA and written representations made to SCANA, all filings on behalf of such persons were made on a timely basis in 2006. Sharon A. Decker, a Director of SCANA, filed one late Form 4 with respect to one transaction.

Shareholder Proposals and Nominations

In order to be considered for inclusion in SCANA's proxy statement and proxy card for the 2008 Annual Meeting, a shareholder proposal must be received at the principal office of SCANA Corporation, c/o Corporate Secretary, 1426 Main Street, Mail Code 13-4, Columbia, South Carolina 29201, by November 16, 2007. Securities and Exchange Commission rules contain standards for determining whether a shareholder proposal is required to be included in a proxy statement.

Under SCANA's bylaws, any shareholder who intends to present a proposal, or nominate an individual to serve as a director, at the 2008 Annual Meeting, must notify SCANA no later than November 16, 2007 of his 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, 1426 Main Street, Mail Code 13-4, Columbia, South Carolina 29201.

Expenses of Solicitation

This solicitation of proxies is being made by the Board of Directors of SCANA. 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. SCANA has retained Georgeson, Inc., 17 State Street, 10th Floor, New York, NY, 10004, to assist in the solicitation of proxies for the Annual Meeting at a fee of $6,000 plus associated costs and expenses.

In addition to the use of the mail, proxies may be solicited personally, by telephone or by SCANA officers and employees without additional compensation.

Availability of Form 10-K

SCANA has filed with the Securities and Exchange Commission its Annual Report on Form 10-K for the fiscal year ended December 31, 2006. A copy of the Form 10-K, including the financial statements and financial schedules and a list of exhibits, will be provided without charge to each shareholder to whom this proxy statement is delivered upon the receipt by SCANA 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 the Form 10-K should be directed to:

H. John Winn III
Director-Investor Relations and
Shareholder Services
SCANA Corporation
1426 Main Street, Mail Code 05-4
Columbia, South Carolina 29201

Incorporation by Reference

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

Neither the Compensation Committee Report, the Audit Committee Report, nor the information set forth under the caption "Performance Graph" 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.

Tickets to the Annual Meeting

An admission ticket to the meeting is detachable from your proxy card. If you plan to attend the Annual Meeting, please so indicate when you vote.

If your shares are owned jointly and you need an additional ticket, you should contact the Corporate Secretary, SCANA Corporation, 1426 Main Street, Mail Code 13-4, Columbia, South Carolina 29201, or call toll-free 1-866-217-9683.

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 9, 2007 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 9, 2007.

SCANA CORPORATION

Lynn M. Williams
Corporate Secretary
March 16, 2007

FINANCIAL APPENDIX

Index to Annual Financial Statements, Management's Discussion and Analysis and Related Annual Report Information:
	Selected Financial and Other Statistical Data	F-2
	SCANA's Business	F-4
	Management's Discussion and Analysis of Financial Condition and Results of Operations	F-6
	Quantitative and Qualitative Disclosures about Market Risk	F-31
	Report of Independent Registered Public Accounting Firm — Consolidated Financial Statements	F-33
	Consolidated Balance Sheets	F-34
	Consolidated Statements of Income	F-36
	Consolidated Statements of Cash Flows	F-37
	Consolidated Statements of Changes in Common Equity and Comprehensive Income	F-38
	Notes to Consolidated Financial Statements	F-39
	Management Report on Internal Control Over Financial Reporting	F-70
	Attestation Report of Independent Registered Public Accounting Firm on Management's Assessment of Internal Control Over Financial Reporting	F-71
	Market for Common Equity and Related Stockholder Matters	F-73
	Executive Officers	F-74
	Certifications	F-74

F-1

SELECTED FINANCIAL AND OTHER STATISTICAL DATA

			(Millions of dollars, except statistics and per share amounts)
As of or for the Year Ended December 31,			2006		2005		2004		2003		2002
Statement of Operations Data
	Operating Revenues		$4,563		$4,777		$3,885		$3,416		$2,954
	Operating Income		603		436		596		551		514
	Other Income (Expense)		(164	)	(162	)	(219	)	(138	)	(397	)
	Income Before Cumulative Effect of Accounting Change		304		320		257		282		88
	Net Income (Loss)		310		320		257		282		(142	)
Common Stock Data
	Weighted Average Number of Common Shares Outstanding (Millions)		115.8		113.8		111.6		110.8		106.0
	Basic and Diluted Earnings (Loss) Per Share		$2.68		$2.81		$2.30		$2.54		$(1.34	)
	Dividends Declared Per Share of Common Stock		$1.68		$1.56		$1.46		1.38		$1.30
Balance Sheet Data
	Utility Plant, Net		$7,007		$6,734		$6,762		$6,417		$5,474
	Total Assets		9,817		9,519		9,006		8,458		8,074
	Capitalization:
		Common equity	$2,846		$2,677		$2,451		$2,306		$2,177
		Preferred Stock (Not subject to purchase or sinking funds)	106		106		106		106		106
		Preferred Stock, net (Subject to purchase or sinking funds)	8		8		9		9		9
		SCE&G-Obligated Mandatorily Redeemable Preferred Securities of SCE&G Trust I	—		—		—		—		50
		Long-term Debt, net	3,067		2,948		3,186		3,225		2,834

		Total Capitalization	$6,027		$5,739		$5,752		$5,646		$5,176

Other Statistics
	Electric:
		Customers (Year-End)	623,402		609,971		585,264		570,940		560,224
		Total sales (Million KWh)	24,523		25,309		25,031		22,516		23,085
		Generating capability-Net MW (Year-End)	5,749		5,808		5,817		4,880		4,866
		Territorial peak demand-Net MW	4,820		4,820		4,574		4,474		4,404
	Regulated Gas:
		Customers (Year-End)	738,317		716,794		693,172		672,849		657,950
		Sales, excluding transportation (Thousand Therms)	996,173		1,106,526		1,124,555		1,205,730		1,354,400
	Retail Gas Marketing:
		Retail customers (Year-End)	482,822		479,382		472,468		415,573		374,872
		Firm customer deliveries (Thousand Therms)	335,896		379,913		379,712		356,256		337,858
	Nonregulated interruptible customer deliveries (Thousand Therms)		1,239,926		1,010,066		917,875		735,902		852,608

Significant events affecting historical earnings trends include the following:

In 2006 SCANA Corporation (SCANA, and together with its subsidiaries, the Company) reduced a litigation accrual by $4.7 million or $.04 per share as a result of litigation being settled for an amount that was less than had been accrued in 2004 (see below). In addition, SCANA recorded as the cumulative effect of an accounting change a gain of $5.8 million or $.05 per share related to reduced share-based compensation upon adoption of Statement of Financial Accounting Standards (SFAS) No. 123(R).

In 2005 SCANA recognized a gain of $4 million or $.03 per share upon receipt of additional proceeds from the 2003 sale of the Company's investment in ITC Holding Company, Inc. (ITC Holding). These additional proceeds had been held in escrow pending resolution of certain contingencies. All of the Company's significant telecommunications investments have been monetized.

In 2004 SCANA recognized losses and recorded impairment charges totaling $29.8 million or $.27 per share in connection with the valuation and sale of substantially all of the Company's holdings in ITC^Deltacom, Inc. (ITC^DeltaCom) and Knology, Inc. (Knology).

F-2

Also, SCANA recorded a charge of $11.1 million or $.10 per share related to pending litigation associated with the 1999 sale of the Company's propane assets.

In 2003 SCANA recognized a gain of $39 million or $.35 per share in connection with the sale of ITC Holding. In addition, SCANA recorded impairment charges of $35 million or $.31 per share on its investment in Knology.

In 2002 SCANA recorded impairment losses on its investments in Duetsche Telekom AG (DTAG) of $182 million or $1.72 per share and ITC^DeltaCom of $7 million or $.07 per share. Also, upon adoption of SFAS 142 SCANA recorded as the cumulative effect of an accounting change an impairment charge of $230 million or $2.17 per share related to the Public Service Company of North Carolina, Incorporated (PSNC Energy) acquisition adjustment. In addition, SCANA recognized gains of $9 million or $.09 per share from the sale of a radio service network and $15 million or $.15 per share in connection with its sale of DTAG.

F-3

SCANA'S BUSINESS

Regulated Utilities

South Carolina Electric & Gas Company (SCE&G) is a public utility that generates, transports and sells electricity to 623,400 customers and buys, sells and transports natural gas to 297,000 customers (each as of December 31, 2006). 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 more than 23,000 square miles. More than 3.0 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 synthetic fibers, chemicals, fiberglass, paper and wood, metal fabrication, stone, clay and sand mining and processing and textile manufacturing.

South Carolina Generating Company, Inc. (GENCO) owns the A.M. Williams Generating Station and sells electricity solely to SCE&G.

South Carolina Fuel Company, Inc. (Fuel Company) acquires, owns and provides financing for SCE&G's nuclear fuel, fossil fuel and emission allowances.

PSNC Energy is a public utility that buys, sells and transports natural gas to 441,500 residential, commercial and industrial customers (as of December 31, 2006). PSNC Energy serves 28 franchised counties covering 12,000 square miles in North Carolina. The industrial customers of PSNC Energy include manufacturers or processors of ceramics and clay products, glass, automotive products, pharmaceuticals, plastics, metals and a variety of food and tobacco products.

Effective November 1, 2006, SCG Pipeline, Inc. merged into South Carolina Pipeline Corporation (SCPC) and the merged company changed its name to Carolina Gas Tranmission Corporation (CGTC). CGTC operates as an open access, transportation-only interstate pipeline company regulated by the Federal Energy Regulatory Commission (FERC). CGTC operates in southeastern Georgia and in South Carolina and has interconnections with Southern Natural Gas Company (Southern Natural) at Port Wentworth, Georgia and with Southern LNG, Inc. at Elba Island, near Savannah, Georgia. CGTC also has interconnections with Southern Natural in Aiken County, South Carolina, and with Transcontinental Gas Pipeline Corporation in Cherokee and Spartanburg counties, South Carolina. CGTC's customers include SCE&G (which uses natural gas for electricity generation and for gas distribution to retail customers), SCANA Energy Marketing, Inc. (SEMI) (which markets natural gas to industrial and sale for resale customers, primarily in the Southeast), other natural gas utilities, municipalities and county gas authorities, and industrial customers primarily engaged in the manufacturing or processing of ceramics, paper, metal, food and textiles.

Prior to the November 1, 2006 merger, SCPC was an intrastate natural gas pipeline engaged in the purchase, transmission and sale of natural gas on a wholesale basis to distribution companies (including SCE&G) and industrial customers throughout most of South Carolina. SCG Pipeline had provided interstate transportation services for natural gas to southeastern Georgia and South Carolina.

F-4

Nonregulated Businesses

SEMI markets natural gas primarily in the southeast and provides energy-related risk management services. SCANA Energy, a division of SEMI, markets natural gas to over 475,000 customers (as of December 31, 2006) in Georgia's natural gas market. The Georgia Public Service Commission (GPSC) has contracted with SCANA Energy to serve as the state's regulated provider until August 31, 2007. Included in the above customer count, SCANA Energy serves over 90,000 customers (as of December 31, 2006) under this regulated provider contract, which includes low-income and high credit risk customers. SCANA Energy's total customer base represents over a 30% share of the approximately 1.5 million customers in Georgia's retail natural gas market. SCANA Energy remains the second largest natural gas marketer in the state.

SCANA Communications, Inc. (SCI) owns and operates a 500-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 1,742 miles of fiber in South Carolina, North Carolina and Georgia. SCI also provides tower site construction, management and rental services in South Carolina and North Carolina.

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

Primesouth, Inc. provides power plant management and maintenance services. Primesouth also operates a synthetic fuel production facility owned by non-affiliates and receives management fees, royalties and expense reimbursements related to those activities.

Service Company

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

F-5

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cautionary Statement Regarding Forward-Looking Information

Statements included in this discussion and analysis (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, estimated construction and other expenditures and factors affecting the availability of synthetic fuel tax credits. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "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 and environmental regulations;
(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 interruptible markets;
(6): growth opportunities for SCANA's regulated and diversified subsidiaries;
(7): the results of financing efforts;
(8): changes in SCANA's or its subsidiaries' accounting rules and accounting policies;
(9): weather conditions, especially in areas served by SCANA's subsidiaries;
(10): payment by counterparties as and when due;
(11): 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;
(12): performance of the Company's pension plan assets;
(13): inflation;
(14): compliance with regulations; and
(15): the other risks and uncertainties described from time to time in the periodic reports filed by SCANA or its subsidiaries with the United States Securities and Exchange Commission.

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

F-6

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 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 perform power plant management and maintenance services, provide fiber optic and other telecommunications services, and provide service contracts to homeowners on certain home appliances and heating and air conditioning units. Additionally, a service company subsidiary of SCANA provides administrative, management and other services to the other subsidiaries.

The following map indicates areas where the Company's significant business segments conducted 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 and the percentage of total assets held by them.

% of Revenues	2006	2005	2004
Regulated	69%	69%	71 %
Nonregulated	31%	31%	29 %
% of Net Income (Loss)	2006(a)	2005	2004(b)
Regulated	89%	92%	106 %
Nonregulated	11%	8%	(6)%
% of Assets	2006	2005	2004
Regulated	93%	94%	94 %
Nonregulated	7%	6%	6 %

^(a): In 2006, net income for nonregulated businesses included a reduction of a litigation accrual upon the settlement of that litigation. See Results of Operations for more information.
^(b): In 2004, net income for regulated businesses totaled $272.0 million and net loss for nonregulated businesses totaled $14.9 million. Net loss for nonregulated businesses included impairments and losses ($29.8 million, net of taxes) recognized on the sale of certain of the Company's telecommunications investments and a charge ($11.1 million, net of taxes) related to pending litigation associated with the Company's 1999 sale of its propane assets.

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Key earnings drivers for the Company over the next five years will be additions to utility rate base at SCE&G and PSNC Energy, consisting primarily of capital expenditures for environmental facilities, new generating capacity and system expansion. Other factors that will impact future earnings growth include the regulatory environment, customer growth in each of the regulated utility businesses, consistent earnings growth in the natural gas marketing business in Georgia and controlling the growth of operation and maintenance expenses.

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, 2006 SCE&G provided electricity to 623,400 customers in an area covering nearly 17,000 square miles. GENCO owns and operates a coal-fired generation station and sells electricity solely to SCE&G. Fuel Company acquires, owns and provides financing for SCE&G's nuclear fuel, fossil fuel and emission allowance requirements.

Operating results for electric operations are primarily driven by customer demand for electricity, the ability to control costs and rates allowed to be charged to customers. Embedded in the rates charged to customers is an allowed regulatory return on equity. SCE&G's allowed return on equity is not to exceed 11.4%, with rates set at 10.7%. 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.

Legislative and regulatory initiatives, including the Energy Policy Act of 2005 (the "Energy Policy Act") also could significantly impact the results of operations and cash flows for the electric operations segment. The Energy Policy Act became law in August 2005, and it provides, among other things, for the establishment of an electric reliability organization (ERO) to propose and enforce mandatory reliability standards for transmission systems, for procedures governing enforcement actions by the ERO and FERC and for procedures under which the ERO may delegate authority to a regional entity to enforce reliability standards.

In February 2006 FERC issued final rules to implement the electric reliability provisions of the Energy Policy Act. The Company is reviewing these rules and monitoring their implementation to determine the impact they may have on SCE&G's access to or cost of power for its native load customers and for its marketing of power outside its service territory. The Company cannot predict when or if FERC will advance other regulatory initiatives related to the national energy market or what conditions such initiatives would impose on utilities.

New legislation may also impose stringent requirements on power plants to reduce emissions of sulfur dioxide, nitrogen oxides and mercury. It is also possible that new initiatives will be introduced to reduce carbon dioxide emissions. The Company cannot predict whether such legislation will be enacted, and if it is, the conditions it would impose on utilities.

Gas Distribution

The gas distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy, and is primarily engaged in the purchase, transmission and sale of natural gas to retail customers in portions of North Carolina and South Carolina. At December 31, 2006 this segment provided natural gas to 738,500 customers in areas covering 35,000 square miles.

Operating results for gas distribution are primarily influenced by customer demand for

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natural gas, the ability to control costs and allowed rates to be charged to customers. Embedded in the rates charged to customers is an allowed regulatory return on equity.

Demand for natural gas is primarily affected by weather, customer growth, the economy and, for commercial and industrial customers, the availability and price of alternate fuels. Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and impact the Company's ability to retain large commercial and industrial customers. Significant supply disruptions occurred in September and October 2005 following hurricane activity in the Gulf of Mexico, resulting in the curtailment during the period of most large commercial and industrial customers with interruptible supply agreements. While supply disruptions were not experienced in 2006 or in January or February of 2007, the price of natural gas remains volatile and has resulted in short-term competitive pressure. The long-term impact of volatile gas prices and gas supply has not been determined.

Gas Transmission

Effective November 1, 2006, SCG Pipeline merged into SCPC, and the merged company changed its name to Carolina Gas Transmission Corporation. CGTC operates an open access, transportation-only interstate pipeline company regulated by FERC. CGTC's operating results are primarily influenced by customer demand for natural gas, the ability to control costs and allowed rates to be charged to customers. Demand for CGTC's services is closely linked to demand for natural gas and is affected by the price of alternate fuels and customer growth. CGTC provides transportation services to SCE&G for its gas distribution customers and for certain electric generation needs and to SEMI for natural gas marketing. CGTC also provides transportation services to other natural gas utilities, municipalities and county gas authorities and to industrial customers.

Prior to the merger, the gas transmission segment was comprised solely of SCPC, which owned and operated an intrastate pipeline engaged in the purchase, transmission and sale of natural gas on a wholesale basis to distribution companies (including SCE&G) and industrial customers throughout most of South Carolina. SCPC's operating results were primarily influenced by customer demand for natural gas, the ability to control costs and allowed rates to be charged to customers.

Retail Gas Marketing

SCANA Energy, a division of SEMI, comprises the retail gas marketing segment. This segment markets natural gas to over 475,000 customers (as of December 31, 2006) throughout Georgia. SCANA Energy's total customer base represents over a 30% share of the approximately 1.5 million customers in Georgia's deregulated natural gas market. SCANA Energy remains the second largest natural gas marketer in the state. SCANA Energy's competitors include affiliates of other large energy companies 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.

As Georgia's regulated provider, SCANA Energy serves low-income customers and customers unable to obtain or maintain natural

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gas service from other marketers at rates approved by the GPSC, and it receives funding from the Universal Service Fund for some of the bad debt associated with the low-income group. SCANA Energy's service as Georgia's regulated provider of natural gas ends August 31, 2007. In February 2007, the GPSC initiated a request for proposal (RFP) bidding process which may be used to select a regulated provider for a new term. Notwithstanding that process, in which SCANA Energy is expected to participate, the GPSC may elect to extend SCANA Energy's current contract term by one year. SCANA Energy files financial and other information periodically with the GPSC, and such information is available at www.psc.state.ga.us. At December 31, 2006, SCANA Energy's regulated division served over 90,000 customers.

SCANA Energy and SCANA's other natural gas distribution and marketing segments maintain gas inventory and also utilize forward contracts and financial instruments, including futures contracts and options, to manage their exposure to fluctuating commodity natural gas prices. See Note 9 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 producers and customers.

The operating results for energy marketing are primarily influenced by customer demand for natural gas and the ability to control 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 tied to the market share held by SCANA Energy in the retail market.

RESULTS OF OPERATIONS

The Company's reported earnings are determined in accordance with GAAP. Management believes that, in addition to reported earnings under GAAP, the Company's GAAP-adjusted net earnings from operations provide a meaningful representation of its fundamental earnings power and can aid in performing period-over-period financial analysis and comparison with peer group data. In management's opinion, GAAP-adjusted net earnings from operations are a useful indicator of the financial results of the Company's primary businesses. This measure is also a basis for management's provision of earnings guidance and growth projections, and it is used by management in making resource allocation and other budgetary and operational decisions. This non-GAAP performance measure is not intended to replace the GAAP measure of net earnings, but is offered as a supplement to it. A reconciliation of reported (GAAP) earnings per share to GAAP-adjusted net earnings from

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operations per share, as well as cash dividend information, is provided in the table below:

		2006			2005			2004
Reported (GAAP) earnings per share		$	2.68		$	2.81		$	2.30
Add (Deduct):
	Cumulative effect of accounting change, net of tax		(.05	)		—			—
	Charge (reduction in charge) related to propane litigation		(.04	)		—			.10
	Gains from sales of telecommunications investments		—			(.03	)		—
	Losses from sales of telecommunications investments		—			—			.14
	Telecommunications investment impairments		—			—			.13

	GAAP-adjusted net earnings from operations per share	$	2.59		$	2.78		$	2.67

	Cash dividends declared (per share)	$	1.68		$	1.56		$	1.46

Discussion of above adjustments:

The cumulative effect of an accounting change in 2006 resulted from the Company's adoption of Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), "Share-Based Payment" (SFAS 123(R)).

The charge related to propane litigation recognized in 2004 resulted from an unfavorable verdict in a case in which an unsuccessful bidder for the 1999 purchase of certain of the Company's propane gas assets alleged breach of contract and related claims. The litigation was settled in 2006 for an amount that was less than had been previously accrued. See also Note 10 to the consolidated financial statements.

Realized gains in 2005 and realized losses in 2004 were recognized on sales of telecommunications investments. Unrealized impairments on certain of these investments were recognized in 2004. All significant telecommunications investments have been monetized.

Management believes that all of the above adjustments are appropriate in determining the non-GAAP financial performance measure. Management utilizes such measure itself in exercising budgetary control, managing business operations and determining eligibility for certain incentive compensation payments. Such non-GAAP measure is based on management's decision that the passive telecommunications investments were not a part of the Company's core businesses and would not be available to provide earnings on a long-term basis. The non-GAAP measure also provides a consistent basis upon which to measure performance by excluding the effects on per share earnings of transactions involving the Company's telecommunications investments and the litigation charge (and reduction) related to the sale of a prior business.

Pension Income

Pension income was recorded on the Company's financial statements as follows:

Millions of dollars		2006		2005		2004
Income Statement Impact:
	Reduction in employee benefit costs	$	0.7	$	4.3	$	2.9
	Other income		12.3		11.9		10.8
Balance Sheet Impact:
	Reduction in capital expenditures		0.3		1.3		1.0
	Component of amount due to Summer Station co-owner		0.2		0.6		0.4

Total Pension Income		$	13.5	$	18.1	$	15.1

For the last several years, the market value of the Company's retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. Among the reasons 2006's income was lower than 2005's was a reduction of the assumed long-term rate of return on plan assets from 9.25% to 9%. See also the discussion of pension accounting in Critical Accounting Policies and Estimates.

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Allowance for Funds Used During Construction (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 2.0% of income before income taxes in 2006, 1.4% in 2005 and 6.8% in 2004. The lower level of AFC for 2005 is primarily due to reductions in the levels of capital expenditures subsequent to the completion of the Jasper County Electric Generating Station in May 2004 and completion of the Lake Murray back-up dam project in May 2005.

Electric Operations

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

Millions of dollars		2006		% Change		2005		% Change		2004
Operating revenues		$	1,877.6	(1.6	)%	$	1,908.3	13.1	%	$	1,687.7
Less: Fuel used in generation			615.1	(0.5	)%		618.3	32.4	%		466.9
	Purchased power		27.5	(26.1	)%		37.2	(26.6	)%		50.7

	Margin	$	1,235.0	(1.4	)%	$	1,252.8	7.1	%	$	1,170.1

•		2006 vs 2005		Margin decreased by $20.8 million due to unfavorable weather, by $16.0 million due to decreased off-system sales and by $6.5 million due to lower industrial sales. These decreases were offset by residential and commercial customer growth of $26.5 million. Purchased power cost decreased due to lower volumes.
•		2005 vs 2004		Margin increased by $41.4 million due to increased retail electric rates that went into effect in January 2005, by $24.8 million due to residential and commercial customer growth and by $16.4 million due to increased off-system sales. These increases were offset by a $2.4 million decrease due to unfavorable weather. Fuel used in generation increased $151.4 million due primarily to the increased cost of coal and natural gas used for electric generation. Purchased power cost decreased due to greater availability of generation facilities.

Megawatt hour (MWh) sales volumes related to the electric margin above, by class, were as follows:

Classification (in thousands)	2006	% Change		2005	% Change		2004
Residential	7,598	(0.5	)%	7,634	2.3	%	7,460
Commercial	7,249	1.9	%	7,117	3.1	%	6,900
Industrial	6,183	(6.0	)%	6,581	(2.9	)%	6,775
Sales for resale (excluding interchange)	1,487	—		1,487	(2.5	)%	1,525
Other	531	0.8	%	527	0.2	%	526

Total territorial	23,048	(1.3	)%	23,346	0.7	%	23,186
Negotiated Market Sales Tariff (NMST)	1,475	(24.9	)%	1,963	6.4	%	1,845

Total	24,523	(3.1	)%	25,309	1.1	%	25,031

•		2006 vs 2005		Territorial sales volumes decreased by 307 MWh due to lower industrial sales volumes and by 406 MWh due to unfavorable weather. These decreases were partially offset by 408 MWh due to residential and commercial customer growth.
•		2005 vs 2004		Territorial sales volumes increased by 407 MWh primarily due to customer growth partially offset by 261 MWh due to less favorable weather.

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Gas Distribution

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

Millions of dollars		2006		% Change		2005		% Change		2004
Operating revenues		$	1,078.0	(7.8	)%	$	1,168.6	27.9	%	$	913.9
Less: Gas purchased for resale			787.1	(12.0	)%		894.6	36.6	%		655.1

	Margin	$	290.9	6.2	%	$	274.0	5.9	%	$	258.8

•		2006 vs 2005		Margin increased by $17.5 million due to increased retail gas base rates which became effective with the first billing cycle in November 2005 and by $4.0 million due to an SCPSC-approved increase in SCE&G's retail gas base rates effective with the first billing cycle in November 2006. These increases were offset by $4.0 million due to lower firm margin resulting from customer conservation at SCE&G. The NCUC-approved rate increase at PSNC Energy, effective with the first billing cycle in November 2006, increased margin by $2.4 million, but was offset primarily by customer conservation.
•		2005 vs 2004		Margin increased primarily due to customer growth of $6.9 million at PSNC Energy, higher firm margin of $4.7 million at SCE&G and $4.6 million due to increased retail gas base rates at SCE&G which became effective with the first billing cycle in November 2005. These increases were offset by a $0.8 million decrease due to lower interruptible margin and transportation revenue at SCE&G.

Dekatherm (DT) sales volumes by class, including transportation gas, were as follows:

Classification (in thousands)	2006	% Change		2005	% Change		2004
Residential	32,879	(13.2	)%	37,860	1.7	%	37,231
Commercial	25,718	(7.3	)%	27,750	1.8	%	27,271
Industrial	21,209	1.8	%	20,833	7.8	%	19,320
Transportation gas	30,147	8.8	%	27,698	(1.8	)%	28,216
Sales for resale	—	—		—	(100.0	)%	1

Total	109,953	(3.7	)%	114,141	1.9	%	112,039

•		2006 vs 2005		Residential and commercial sales volumes decreased primarily due to milder weather and conservation. Transportation sales volumes increased primarily due to interruptible customers using gas instead of alternate fuels.
•		2005 vs 2004		Commercial and industrial sales volumes increased primarily due to more customers buying commodity gas instead of purchasing alternate fuels and instead of transporting gas purchased from others.

Gas Transmission

Gas Transmission is comprised of the operations of CGTC and, for periods prior to the merger and name change, SCPC and SCG Pipeline for all periods presented. Gas transmission transportation revenues and sales margins (including transactions with affiliates) were as follows:

Millions of dollars		2006		% Change		2005		% Change		2004
Transportation revenue		$	26.5	40.2	%	$	18.9	6.2	%	$	17.8
Other operating revenues			475.0	(26.5	)%		646.3	19.6	%		540.2
Less: Gas purchased for resale			439.2	(27.3	)%		604.2	21.6	%		496.9

	Margin	$	62.3	2.1	%	$	61.0	(0.2	)%	$	61.1

•		2006 vs 2005		Margin increased by $6.2 million due to increased transportation capacity charges (as a result of the merger discussed previously in the Overview section) and by $1.4 million due to higher interruptible transportation revenues, offset by $1.8 million due to decreased firm sales capacity charges and by $4.5 million due to lower industrial margins.
•		2005 vs 2004		Operating revenues and gas purchased for resale increased primarily due to higher commodity gas prices.

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DT sales volumes by class, including transportation, were as follows:

Classification (in thousands)	2006	% Change		2005	% Change		2004
Commercial	23	(57.4	)%	54	(52.2	)%	113
Industrial	18,875	(17.0	)	22,748	(20.5	)%	28,625
Transportation	57,546	27.7		45,055	18.3	%	38,078
Sales for resale	33,327	(23.8	)	43,763	1.9	%	42,946

Total	109,771	(1.7	)	111,620	1.7	%	109,762

•		2006 vs 2005		Prior to the merger on November 1, 2006, industrial volumes decreased primarily due to higher commodity gas prices relative to alternate fuels. Subsequent to the merger, CGTC operates as a transportation-only interstate pipeline.
•		2005 vs 2004		Industrial volumes decreased primarily due to higher commodity gas prices relative to alternate fuels.

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		2006			% Change		2005			% Change		2004
Operating revenues		$	608.1		(8.4	)%	$	664.0		20.3	%	$	552.0
Net income			30.1		24.9	%		24.1		(16.9	)%		29.0

•		2006 vs 2005		Operating revenues decreased primarily due to milder weather and customer conservation, resulting in lower customer usage, which was partially offset by higher average retail prices arising from higher commodity gas costs. Net income increased primarily due to decreased bad debt of $9.0 million and lower operating and customer service expenses of $6.2 million, partially offset by a margin decrease of $9.1 million, net of taxes.
•		2005 vs 2004		Operating revenues increased primarily as a result of higher average retail prices necessitated by higher commodity cost of gas. Net income decreased primarily due to increased bad debt of $5.9 million, and operating, marketing and customer service expenses of $4.4 million, offsetting a margin increase of $5.2 million, net of taxes.

Delivered volumes totaled 33.6 million DT in 2006 and 37.9 million DT in each of 2005 and 2004. Volumes declined in 2006 compared to 2005 and 2004 due to milder weather and customer conservation.

Energy Marketing

Energy Marketing is comprised of the Company's nonregulated marketing operations, excluding SCANA Energy. Energy Marketing operating revenues and net loss were as follows:

Millions of dollars		2006			% Change		2005			% Change		2004
Operating revenues		$	948.7		0.3	%	$	945.5		58.5	%	$	596.5
Net loss			(0.4	)	(33.3	)%		(0.6	)	(70.0	)%		(2.0	)

•		2006 vs 2005		Operating revenues increased due primarily to higher sales volume. Net loss decreased due to lower operating expenses of $1.0 million, offset by lower margin on sales of $0.9 million.
•		2005 vs 2004		Operating revenues increased due to higher market prices and higher sales volume. Net loss decreased primarily due to higher margins of $0.6 million and lower operating expenses of $0.8 million.

Delivered volumes totaled 123.9 million DT in 2006, 101.0 million DT in 2005 and 91.8 million DT in 2004. Delivered volumes increased in 2006 compared to 2005 primarily as a result of increased service to electric generation facilities and municipalities in Georgia and South Carolina. Delivered volumes increased in 2005 compared to 2004 primarily as a result of the commencement of service to SCE&G's Jasper County Electric Generating Station in 2004.

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Other Operating Expenses

Other operating expenses arising from the operating segments previously discussed were as follows:

Millions of dollars	2006		% Change		2005		% Change		2004
Other operation and maintenance	$	619.2	(2.0	)%	$	632.0	4.0	%	$	607.5
Depreciation and amortization		332.4	(34.8	)%		509.9	92.3	%		265.1
Other taxes		151.8	4.7	%		145.0	(0.4	)%		145.6

Total	$	1,103.4	(14.3	)%	$	1,286.9	26.4	%	$	1,018.2

•		2006 vs 2005		Other operation and maintenance expenses decreased by $13.9 million due to lower bad debts and by $9.5 million due to lower operating and customer service expenses, both at Retail Gas Marketing, and by $22.5 million due to decreased incentive compensation expense. These decreases were partially offset by $11.1 million due to increased electric, generation, transmission and distribution expenses, by $3.1 million due to increased gas distribution expenses, by $3.6 million due to lower pension income and by $2.0 million due to higher customer service expenses at SCE&G. Depreciation and amortization expense decreased by $185.8 million due to lower accelerated depreciation of the back-up dam at Lake Murray in 2006 (see Income Taxes — Recognition of Synthetic Fuel Tax Credits), partially offset by $6.7 million due to property additions and higher depreciation rates at SCE&G. Other taxes increased primarily due to higher property taxes.
•		2005 vs 2004		Other operation and maintenance expenses increased primarily due to increased electric generation major maintenance expenses of $6.7 million, increased expenses associated with the Jasper County Electric Generating Station completed in May 2004 totaling $2.4 million, increased nuclear operating and maintenance expenses of $2.4 million, higher expenses related to regulatory matters of $1.9 million and higher amortization of regulatory assets of $3.6 million. The increases were offset primarily by decreased incentive compensation of $4.8 million and decreased storm damage expenses of $0.9 million (at SCE&G). Depreciation and amortization increased approximately $214.0 million due to accelerated depreciation of the back-up dam at Lake Murray (see Income Taxes — Recognition of Synthetic Fuel Tax Credits), increased $6.5 million due to the completion of the Jasper County Electric Generating Station in May 2004 and increased $6.1 million due to normal net property changes at SCE&G. In addition, as a result of the January 2005 rate order, SCE&G received approval to amortize previously deferred purchased power costs and to implement new depreciation rates, resulting in $17.3 million of additional depreciation and amortization expense in the period.

Other Income (Expense)

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

Millions of dollars	2006			% Change		2005			% Change		2004
Gain (loss) on sale of investments	$	—		(100.0	)%	$	7.2		*		$	(21.2	)
Gains on sales of assets		3.4		100.0	%		1.7		*			0.7
Impairment of investments		—		—			—		(100.0	)%		(26.9	)
Other revenues		141.6		(42.9	)%		248.1		36.9	%		181.2
Other expenses		(93.1	)	(53.5	)%		(200.3	)	25.3	%		(159.9	)

Total	$	51.9		(8.5	)%	$	56.7		*		$	(26.1	)

* Greater than 100%

•		2006 vs 2005		Other revenues decreased $91.5 million due to lower power marketing activities, $10.8 million due to the termination of a contract to operate a steam combustion turbine at the United States Department of Energy (DOE) Savannah River Site, $4.3 million due to lower carrying costs recognized on the unrecovered balance of the Lake Murray back-up dam project and lower management service fees of $10.0 million received by Primesouth, Inc., as discussed at Income Taxes — Recognition of Synthetic Fuel Tax Credits below. These decreases were partially offset by higher interest income of $9.4 million and higher third-party coal sales revenue of $4.8 million.

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		Other expenses decreased by $90.6 million due to lower power marketing activities and $4.4 million due to the termination of the DOE's Savannah River Site contract. These decreases were partially offset by increased charges of $8.7 million related to the settlement of the FERC power marketing matter (see Note 10 to the consolidated financial statements) and higher expenses to support third-party coal sales of $3.6 million.
•	2005 vs 2004	Gain (loss) on sale of investments increased due to the receipt in 2005 of additional proceeds of $6.0 million from the 2003 sale of the Company's investment in ITC Holding. These proceeds had been held in escrow pending resolution of certain contingencies. In 2004 the Company recognized a $21.0 million loss on the sale of investments in Knology and ITC^DeltaCom. In 2004 impairments of $26.9 million were recorded on investments in Knology, ITC Holding and Magnolia Holding.
		Other revenues increased $42.8 million due to higher power marketing activity and $10.9 million due to carrying costs recognized on the unrecovered balance of the Lake Murray back-up dam project.
		Other expenses increased $43.1 million due to higher power marketing activity and $0.8 million due to a charge associated with the FERC power marketing matter. (See Note 10 to the consolidated financial statements.)

Interest Expense

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

Millions of dollars	2006		% Change		2005		% Change		2004
Interest on long-term debt, net	$	190.9	(4.3	)%	$	199.5	0.7	%	$	198.1
Other interest expense		18.7	48.4	%		12.6	*			4.3

Total	$	209.6	(1.2	)%	$	212.1	4.8	%	$	202.4

* Greater than 100%

•		2006 vs 2005		Interest on long-term debt decreased primarily due to reduced long-term borrowings, partially offset by increased variable rates. Other interest expense increased primarily due to increased short-term borrowings.
•		2005 vs 2004		Interest on long-term debt increased primarily due to the lower level of AFC resulting from reductions in the levels of capital expenditures subsequent to the completion of the Jasper County Electric Generating Station in May 2004 and the Lake Murray back-up dam project in May 2005, partially offset by the redemption of outstanding debt in late 2004. Other interest expense increased primarily due to increased short-term borrowings at SCE&G.

Income Taxes

Income taxes, exclusive of amounts related to the cumulative effect of an accounting change, increased in 2006 compared to 2005 by $237.6 million and decreased in 2005 compared to 2004 by $240.8 million. Changes in income taxes are primarily due to changes in operating income and other income, although in 2005 the benefits of synthetic fuel credits of $179.0 million were also recognized pursuant to the January 2005 electric rate order. The Company's effective tax rate has been favorably impacted in recent years by the flow-through of state investment tax credits and the equity portion of AFC.

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Recognition of Synthetic Fuel Tax Credits

SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel, the use of which fuel qualifies for federal income tax credits. Under an accounting plan approved by the Public Service Commission of South Carolina (SCPSC) in June 2000, the synthetic fuel tax credits generated by the partnerships and passed through to SCE&G, net of partnership losses and other expenses, were deferred until the SCPSC approved its application to offset capital costs of the Lake Murray back-up dam project. Under the accounting methodology approved by the SCPSC in a January 2005 order, construction costs related to the project were recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

The level of depreciation expense and related tax benefit recognized in the income statement is equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of taxes. As a result, the balance of unrecovered costs in the dam remediation account declines as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, they have a significant impact on individual line items within the income statement. The accelerated depreciation, synthetic fuel tax credits, partnership losses and the income tax benefit arising from such losses recognized by SCE&G during 2006 and 2005 are as follows:

Millions of dollars		2006			2005
Depreciation and amortization expense		$	(28.2	)	$	(214.0	)
Income tax benefits:
	From synthetic fuel tax credits		30.0			179.0
	From accelerated depreciation		10.8			81.8
	From partnership losses		7.8			28.9

Total income tax benefits			48.6			289.7
Losses from equity method investments			(20.4	)		(75.7	)

Impact on net income		$	—		$	—

The 2005 amounts above reflect the recognition of previously deferred tax credits, while the 2006 amounts reflect the likelihood that credits available in 2006 will be phased down pursuant to regulations which limit the credits based on the relative commodity price of crude oil.

Depreciation on the Lake Murray back-up dam project account will be matched to available synthetic fuel tax credits on a quarterly basis until the balance in the dam remediation account is zero or until all of the available synthetic fuel tax credits have been utilized. The synthetic fuel tax credit program expires at the end of 2007.

The availability of the synthetic fuel tax credits is dependent on several factors, one of which is the average annual domestic wellhead price per barrel of crude oil as published by the U.S. Government. Under a phase-out provision included in the program, if the domestic wellhead reference price of oil per barrel for a given year is below an inflation-adjusted benchmark range for that year, all of the synthetic fuel tax credits that have been generated in that year would be available for use. If that price is above the benchmark range, none of the tax credits would be available. If that price falls within the benchmark range, a calculated portion of the credits would be available.

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The benchmark price range for 2005, published in April 2006, was $53 to $67 per barrel, and no phase-out applied. However, SCE&G's analysis indicates that the available synthetic fuel tax credits for 2006 are likely to be impacted by the phase-out calculation. As such, in 2006 the Company recorded synthetic fuel tax credits and applied those credits to allow the recording of accelerated depreciation related to the balance in the dam remediation project account based on an estimate that only 67% of credits generated will be available (phase-out of 33%). The Company cannot predict what impact, if any, the price of oil may have on the Company's ability to earn and utilize synthetic fuel tax credits in the future. However, there is significant uncertainty as to the continued availability of the credits in 2007. The availability of these synthetic fuel tax credits is also subject to coal availability and other operational risks related to the generating plants.

The Company does not expect available credits to be sufficient to fully recover the construction costs of dam remediation, and total unrecovered costs at the end of 2007 may be significant. To the extent that available credits are not sufficient to fully recover the construction costs of the dam remediation, regulatory action to allow recovery of those remaining costs may be sought. As of December 31, 2006, remaining unrecovered costs, based on management's recording of accelerated depreciation and related tax benefits, were $69.1 million.

Finally, Primesouth, Inc., a subsidiary of SCANA, provides management and maintenance services for a non-affiliated synthetic fuel production facility. Reduced synthetic fuel tax credit availability under the above phase-out provisions also adversely impacts the level of payment Primesouth receives for these services. The fees recognized by Primesouth in 2006 were $10.0 million lower than amounts recognized in 2005.

LIQUIDITY AND CAPITAL RESOURCES

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, if requested.

SCE&G expects to require the addition of base load electrical generation by 2015 and is evaluating alternatives, including fossil and nuclear-fueled generation facilities. In February 2006, SCE&G and the South Carolina Public Service Authority (Santee Cooper), a state-owned utility in South Carolina (joint owners of V. C. Summer Nuclear Station (Summer Station)), announced their selection of the Summer Station site as the preferred site for new nuclear generation facilities should such generation be considered the best alternative in the future. Due to the significant lead time required for construction of nuclear generation facilities, the joint owners are preparing an application to the United States Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL) that would cover two nuclear units. The COL application, which is expected to be completed and filed in 2007, would be reviewed by the NRC for an estimated three years. Issuance of a COL would not obligate the joint owners to build

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nuclear generation facilities. The final decision to build nuclear generation facilities will be influenced by several factors, including NRC licensing attainment, estimates of construction and operating costs, the cost of competing fuels, regulatory and environmental requirements and financial market conditions.

The Company's leverage ratio of debt to capital was 55% at December 31, 2006. If the agencies rating the Company's credit determine that the Company's leverage ratio, among other measures, is too high, these rating agencies may downgrade the Company's debt. Such a downgrade would adversely affect the interest rate the Company is able to obtain when issuing debt, both short- and long-term, and would limit the Company's access to capital markets.

The Company's current estimates of its capital expenditures for construction and nuclear fuel for 2007-2009, which are subject to continuing review and adjustment, are as follows:

Estimated Capital Expenditures

Millions of dollars			2007		2008		2009
SCE&G:
	Electric Plant:
		Generation (including GENCO)	$	220	$	361	$	255
		Transmission		45		52		35
		Distribution		151		155		153
		Other		28		38		17
	Nuclear Fuel			55		6		26
	Gas			50		59		52
	Common and other			28		10		12

		Total SCE&G		577		681		550
Other Companies Combined				151		160		142

		Total	$	728	$	841	$	692

The Company's contractual cash obligations as of December 31, 2006 are summarized as follows:

Contractual Cash Obligations

Millions of dollars		Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Long- and short-term debt (including interest and preferred stock)		$	6,310	$	841	$	900	$	1,151	$	3,418
Capital leases			2		1		1		—		—
Operating leases			57		30		25		—		2
Purchase obligations			647		348		296		2		1
Other commercial commitments			7,513		1,275		2,283		977		2,978

	Total	$	14,529	$	2,495	$	3,505	$	2,130	$	6,399

Included in other commercial commitments are estimated obligations under forward contracts for natural gas purchases. Forward contracts for natural gas purchases include customary "make-whole" or default provisions, but are not considered to be "take-or-pay" contracts. Certain of these contracts relate to regulated businesses; therefore, the effects of such contracts on fuel costs are reflected in electric or gas rates. Also included in other commercial commitments is a "take-and-pay" contract for natural gas which expires in 2019 and estimated obligations for coal and nuclear fuel purchases. See Note 10 to the consolidated financial statements.

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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 obligations without penalty.

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, and no further contributions are anticipated until after 2010. Cash payments under the health care and life insurance benefit plan were $9.7 million in 2006, and such annual payments are expected to increase to the $13-$14 million range in the future.

In addition, the Company is party to certain New York Mercantile Exchange (NYMEX) futures contracts for which any unfavorable market movements are funded in cash. These derivatives are accounted for as cash flow hedges under SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, 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.

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

The Company anticipates that its contractual cash obligations will be met through internally generated funds and the incurrence of additional short- and long-term indebtedness. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future.

Cash outlays for 2006 (actual) and 2007 (estimated) for certain expenditures are as follows:

Millions of dollars		2006		2007
Property additions and construction expenditures, net of AFC		$	527	$	673
Nuclear fuel expenditures			17		55
Investments			25		19

	Total	$	569	$	747

Financing Limits and Related Matters

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

Pursuant to Section 204 of the Federal Power Act, SCE&G and GENCO must obtain FERC authority to issue short-term debt. Effective February 8, 2006 the FERC has authorized SCE&G and GENCO to issue up to $700 million and $100 million, respectively, of unsecured promissory notes or commercial paper with maturity dates of one year or less. This authorization expires February 7, 2008.

At December 31, 2006, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following lines of credit and short-term borrowings outstanding:

Millions of dollars		SCANA			SCE&G			PSNC Energy
Lines of credit (total and unused):
	Committed long-term (expires December 2011)	$	200		$	650		$	250
	Uncommitted		103	^(a)		—			—
Short-term borrowings outstanding:
	Bank loans/commercial paper (270 or fewer days)	$	—		$	362.2		$	124.7
	Weighted average interest rate		—			5.38	%		5.40	%

^(a): SCANA or SCE&G may use $78 million of these lines of credit.

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SCANA Corporation

SCANA has in effect a medium-term note program for the issuance from time to time of unsecured medium-term debt securities. The Indenture under which they are issued contains no specific limit on the amount which may be issued.

South Carolina Electric & Gas Company

In September 2006 SCE&G discharged its bond indenture dated January 1, 1945 which covered substantially all of its properties. SCE&G remains subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its currently outstanding First Mortgage Bonds and all of its future mortgage-backed debt (Bonds) has been and will be 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 will be issuable 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 (2.00) the annual interest requirements on all outstanding Bonds and Bonds to be outstanding (Bond Ratio). For the year ended December 31, 2006, the Bond Ratio was 6.99.

SCE&G's Restated Articles of Incorporation (Articles) prohibit issuance of additional shares of preferred stock without the consent of the preferred shareholders unless net earnings (as therein defined) for the 12 consecutive months immediately preceding the month of issuance are at least one and one-half times (1.50) the aggregate of all interest charges and preferred stock dividend requirements on all shares of preferred stock outstanding immediately after the proposed issue (Preferred Stock Ratio). For the year ended December 31, 2006, the Preferred Stock Ratio was 1.99.

The Articles also require the consent of a majority of the total voting power of SCE&G's preferred stock before SCE&G may issue or assume any unsecured indebtedness if, after such issue or assumption, the total principal amount of all such unsecured indebtedness would exceed ten percent of the aggregate principal amount of all of SCE&G's secured indebtedness and capital and surplus (the ten percent test). No such consent is required to enter into agreements for payment of principal, interest and premium for securities issued for pollution control purposes. At December 31, 2006, the ten percent test would have limited total issuances of unsecured indebtedness to approximately $428.4 million. Unsecured indebtedness at December 31, 2006, totaled approximately $357.8 million, and was comprised primarily of short-term borrowings.

Financing Cash Flows

During 2006 the Company experienced net cash outflows related to financing activities of $83 million primarily due to the payment of dividends, which were partially offset by net increases in long- and short-term borrowings and proceeds from common stock issuances.

The Company uses interest rate swap agreements to manage interest rate risk. These swap agreements provide for the Company to pay variable and receive fixed rate interest payments and are designated as fair value hedges of certain debt instruments. The Company may terminate a swap agreement and may replace it with a new swap also designated as a fair value hedge. Payments received upon termination of such swaps are recorded as basis adjustments to long-term debt and are amortized as reductions to interest expense over the term of the underlying debt. At December 31, 2006, the estimated fair value of the Company's swaps totaled a $0.1 million gain related to combined notional amounts of $44.2 million.

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In anticipation of the issuance of debt, the Company may use interest rate lock or similar swap agreements to manage interest rate risk. Payments received or made upon termination of such agreements are recorded within long-term debt on the balance sheet and are amortized to interest expense over the term of the underlying debt. As permitted by SFAS 104, "Statement of Cash Flows — Net Reporting of Certain Cash Receipts and Cash Payments and Classification of Cash Flows from Hedging Transactions," these proceeds or payments are classified as a financing activity in the consolidated statements of cash flows.

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

On February 15, 2007, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.44 per share, an increase of 4.8%. The new dividend is payable April 1, 2007 to stockholders of record on March 9, 2007.

ENVIRONMENTAL MATTERS

Capital Expenditures

For the three years ended December 31, 2006, the Company's capital expenditures for environmental control totaled $160.2 million. These expenditures were in addition to expenditures included in "Other operation and maintenance" expenses, which were $28.7 million, $25.2 million, and $21.5 million during 2006, 2005 and 2004, respectively. It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for the Company are $154.7 million for 2007 and $494.8 million for the four-year period 2008 through 2011. These expenditures are included in the Company's Estimated Capital Expenditures table, discussed in Liquidity and Capital Resources, and include the matters discussed below.

Electric Operations

In March 2005, the United States Environmental Protection Agency (EPA) issued a final rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. SCE&G has petitioned the United States Court of Appeals for the District of Columbia Circuit to review CAIR. Several other electric utilities have filed separate petitions. The petitioners seek a change in the method CAIR uses to allocate sulfur dioxide emission allowances to a method the petitioners believe is more equitable. The Company believes that installation of additional air quality controls will be needed to meet the CAIR requirements, although compliance plans and cost to comply with the rule have not been determined. Such costs will be material and are expected to be recoverable through rates.

In March 2005, the EPA issued a final rule establishing a mercury emissions cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. Although the Company expects to be able to meet the Phase I limits through those measures it already will be taking to meet its CAIR obligations, it is uncertain as to how the Phase II limits will be met. Assuming Phase II limits remain unchanged, installation of additional air quality controls likely will be required to comply with the rule's Phase II mercury emission caps. Final compliance plans and costs to comply with the rule are still under review. Such costs will be material and are expected to be recoverable through rates.

The EPA has undertaken an aggressive enforcement initiative against the utilities industry, and the United States Department of Justice (DOJ) has brought suit against a number of utilities in federal court alleging violations of the Clean Air Act (CAA). At least two of these suits have either been tried or have had substantive motions decided — one

F-22

favorable to the industry and one not. The one not favorable to the industry is not binding as precedent and the one favorable to the industry likely is precedent and is consistent with current Company interpretation of the law and its resulting maintenance practices. Prior to the suits, those utilities had received requests for information under Section 114 of the CAA and were issued Notices of Violation. The basis for these suits is the assertion by the EPA, under a stringent rule known as New Source Review (NSR), that maintenance activities undertaken by the utilities over the past 20 or more years constitute "major modifications" which would have required the installation of costly Best Available Control Technology (BACT). SCE&G and GENCO have received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. The regulations under the CAA provide certain exemptions to the definition of "major modifications," including an exemption for routine repair, replacement or maintenance. On October 27, 2003, EPA published a final revised NSR rule in the Federal Register with an effective date of December 26, 2003. The rule represents an industry-favorable departure from certain positions advanced by the federal government in the NSR enforcement initiative. However, on motion of several Northeastern states, the United States Circuit Court of Appeals for the District of Columbia stayed the effect of the final rule. The ultimate application of the final rule to the Company is uncertain. The Company has analyzed each of the activities covered by the EPA's requests and believes each of these activities is covered by the exemption for routine repair, replacement and maintenance under what it believes is a fair reading of both the prior regulation and the contested revised regulation. The regulations also provide an exemption for an increase in emissions resulting from increased hours of operation or production rate and from demand growth.

The current state of continued DOJ enforcement actions is the subject of industry-wide speculation, but it is possible that the EPA will commence enforcement actions against SCE&G and GENCO, and the EPA has the authority to seek penalties at the rate of up to $27,500 per day for each violation. The EPA also could seek installation of BACT (or equivalent) at the three plants. The Company believes that any enforcement actions relative to the Company's compliance with the CAA would be without merit. The Company has completed installation of selective catalytic reactors at Wateree and Williams for nitrogen oxides control and is proceeding with plans to install sulfur dioxide scrubbers at both of these stations to meet CAIR regulations. These actions would mitigate many of the concerns with NSR. SCE&G and GENCO expect to incur capital expenditures totaling approximately $450 million over the 2007-2010 period to install this new equipment. SCE&G and GENCO expect to have increased operation and maintenance costs of approximately $4 million in 2010 and $27 million in 2011 and each year thereafter. To meet compliance requirements for the years 2012 through 2016, the Company anticipates additional capital expenditures totaling approximately $480 million.

The Clean Water Act, as amended, provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the Clean Water Act, compliance with applicable limitations is achieved under a national permit program. Discharge permits have been issued for all, and renewed for nearly all, of SCE&G's and GENCO's generating units. Concurrent with renewal of these permits, the permitting agency has implemented a more rigorous program of monitoring and controlling discharges, has modified the requirements for cooling water intake structures, and has required strategies for toxicity reduction in wastewater streams. The Company is conducting studies and is developing or implementing compliance plans for these initiatives. Congress is expected to consider further amendments to the Clean Water Act. Such legislation may include limitations to

F-23

mixing zones and toxicity-based standards. These provisions, if passed, could have a material adverse impact on the financial condition, results of operations and cash flows of the Company, SCE&G and GENCO.

The Nuclear Waste Policy Act of 1982 (Nuclear Waste Act) required that the United States government, by January 31, 1998, accept and permanently dispose of high-level radioactive waste and spent nuclear fuel. 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 (Standard Contract) with the DOE in 1983.

On January 28, 2004, SCE&G and Santee Cooper (one-third owner of Summer Station) filed suit in the Court of Federal Claims against the DOE for breach of the Standard Contract, because as of the date of filing, the federal government had accepted no spent fuel from Summer Station or any other utility for transport and disposal, and has indicated that it does not anticipate doing so until 2010, at the earliest. As a consequence of the federal government's breach of contract, the plaintiffs have incurred and will continue to incur substantial costs. On January 9, 2006, SCE&G and Santee Cooper accepted a $9 million settlement from DOE. The payment reimbursed the plaintiffs for certain costs incurred from January 31, 1998 through July 31, 2005. SCE&G recorded its portion ($6 million) of the settlement as a reduction to its fuel costs. As a result, most of the credit was passed through to its customers through the fuel clause component of its retail electric rates. The settlement also provides for the plaintiffs to submit an annual application to DOE for the reimbursement of certain costs incurred subsequent to July 31, 2005.

SCE&G has on-site spent nuclear fuel storage capability until at least 2018 and expects to be able to expand its storage capacity to accommodate the spent nuclear fuel output for the life of the plant through dry cask storage or other technology as it becomes available.

SCE&G has been named, along with 53 others, by the EPA as a potentially responsible party (PRP) at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia. The EPA placed the site on the National Priorities List on April 19, 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned. While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels. During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils. EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The site has not been remediated, nor has a clean-up cost been estimated. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recoveries, if any, is expected to be recoverable through rates.

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PCB-contaminated soil and groundwater at the site. EPA reports that it has spent $36 million to date. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recoveries, if any, is expected to be recoverable through rates.

Gas Distribution

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. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in deferred debits and amortized with recovery provided through rates.

Deferred amounts for SCE&G, net of amounts previously recovered through rates and insurance settlements, totaled $17.9 million at December 31, 2006 and $17.7 million at December 31, 2005. The deferral includes the estimated costs associated with the following matters.

SCE&G owns a decommissioned manufactured gas plant (MGP) site in the Calhoun Park area of Charleston, South Carolina. SCE&G anticipates that remediation for contamination at the site will be completed in late 2007, with certain monitoring and retreatment activities continuing until 2011. As of December 31, 2006, SCE&G has spent $22.3 million to remediate the Calhoun Park site, and expects to spend an additional $1.1 million. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to this site. SCE&G expects to recover any cost arising from the remediation of this site through rates.

SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. One of the sites has been remediated and will undergo routine monitoring until released by the South Carolina Department of Health and Environmental Control (DHEC). The other sites are currently being investigated under work plans approved by DHEC. SCE&G anticipates that major remediation activities for the three sites will be completed in 2011. As of December 31, 2006, SCE&G has spent $4.8 million related to these three sites, and expects to spend an additional $11.2 million. SCE&G expects to recover any cost arising from the remediation of these sites through rates.

PSNC Energy is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy's 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 $6.9 million, which reflects its estimated remaining liability at December 31, 2006. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates are $0.9 million. PSNC Energy expects to recover any costs allocated to PSNC Energy arising from the remediation of these sites through gas rates.

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REGULATORY MATTERS

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

South Carolina Electric & Gas Company

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

The Natural Gas Stabilization Act of 2005 allows natural gas distribution companies to request annual adjustments to rates to reflect changes in revenues and expenses and changes in investment. Such annual adjustments are subject to certain qualifying criteria and review by the SCPSC.

Public Service Company of North Carolina, Incorporated

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

The United States Congress passed the Pipeline Safety Improvement Act of 2002 (the Pipeline Safety Act), directing the United States Department of Transportation (DOT) to establish the Integrity Management Rule for operations of natural gas systems with transmission pipelines located near moderate to high density populations. Of PSNC Energy's approximately 720 miles of transmission pipeline subject to the Pipeline Safety Act, approximately 110 miles are located within these areas. Fifty percent of these miles of pipeline must be assessed by December 2007, and the remainder by December 2012. Depending on the assessment method used, PSNC Energy will be required to reinspect these same miles of pipeline every five to seven years. Though cost estimates for this project were developed using various assumptions, each of which is subject to imprecision, PSNC Energy currently estimates the total cost through December 2012 to be $8 million for the initial assessments, not including any subsequent remediation that may be required. Effective November 1, 2004 the NCUC authorized deferral accounting for certain expenses incurred to comply with DOT's pipeline integrity management requirements. In accordance with an October 2006 NCUC rate order, $1.4 million in costs incurred and deferred through June 30, 2006 are now being recovered through rates over a three-year period. Additionally, management believes that all subsequent costs will be recoverable by PSNC Energy through rates.

Carolina Gas Transmission Corporation

CGTC has approximately 65 miles of transmission line that are covered by the Integrity Management Rule of the Pipeline Safety Act. Though cost estimates for this project were developed using various assumptions, each of which is subject to imprecision, CGTC currently estimates the total cost to be $10.9 million for the initial assessments and any subsequent remediation required through December 2012.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Utility Regulation

SCANA's regulated utilities are subject to the provisions of SFAS 71, "Accounting for the Effects of Certain Types of Regulation," which require them to record certain assets and liabilities that defer the recognition of expenses and revenues to future periods as a result of being rate-regulated. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory

F-26

assets and liabilities. Such an event could have a material adverse effect on the results of operations, liquidity or financial position of the Company's Electric Distribution and Gas Distribution segments in the period the write-off would be recorded. See Note 1 to the consolidated financial statements for a description of the Company's regulatory assets and liabilities, including those associated with the Company's environmental assessment program.

The Company's generation assets would be exposed to considerable financial risks in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, the Company could be required to write down its investment in those assets. The Company cannot predict whether any write-downs will be necessary and, if they are, the extent to which they would adversely affect the Company's results of operations in the period in which they would be recorded. As of December 31, 2006, the Company's net investments in fossil/hydro and nuclear generation assets were approximately $2.3 billion and $506 million, 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 since the date of the last reading of their meters. Such unbilled revenues reflect consideration of estimated usage by customer class, the effects of different rate schedules, changes in weather and, where applicable, the impact of weather normalization provisions of rate structures. The accrual of unbilled revenues in this manner properly matches revenues and related costs. Accounts receivable included unbilled revenues of $177.6 million at December 31, 2006 and $280.9 million at December 31, 2005, compared to total revenues of $4.6 billion for 2006 and $4.8 billion for 2005.

Provisions for Bad Debts and Allowances for Doubtful Accounts

As of each balance sheet date, the Company evaluates the collectibility of accounts receivable and records allowances for doubtful accounts based on estimates of the level of expected write-offs. These estimates are based on, among other things, comparisons of the relative age of accounts, assigned credit ratings for commercial and industrial accounts, credit scores for residential customers in Georgia when available, and consideration of actual write-off history. The distribution segments of the Company's regulated utilities have established write-off histories and regulated service areas that tend to improve the recoverability of accounts and enable the utilities to reliably estimate their respective provisions for bad debts. The Company's Retail Gas Marketing segment operates in Georgia's deregulated natural gas market in which customers may obtain service from others without necessarily paying outstanding amounts and in which there are certain limitations on the Company's ability to effect timely shut-off of service for nonpayment. As such estimation of the provision for bad debts for these accounts is subject to greater imprecision.

Nuclear Decommissioning

Accounting for decommissioning costs for nuclear power plants involves significant estimates related to costs to be incurred many years in 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

F-27

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).

SCE&G's two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station, including both the cost of decommissioning plant components that are and are not subject to radioactive contamination, totals $451.0 million, stated in 2006 dollars, based on a decommissioning study completed in 2006. The cost estimate assumes that the site would be maintained over a period of 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use. This cost is significantly lower than previous estimates, with the reduction being primarily related to the expectation of lower decommissioning cost escalations than had been assumed in the prior cash flow analysis. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station.

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 on proceeds, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.

Accounting for Pensions and Other Postretirement Benefits

The Company follows SFAS 87, "Employers' Accounting for Pensions," as amended by SFAS 158, "Employees' Accounting for Defined Benefit Pension and Other Postretirement Plans," in accounting for the cost of its defined benefit pension plan. The Company's plan is adequately funded and as such, net pension income is reflected in the financial statements (see Results of Operations — Pension Income). SFAS 87 requires the use of several assumptions, the selection of which may have a large impact on the resulting benefit recorded. Among the more sensitive assumptions are those surrounding discount rates and expected returns on assets. Net pension income of $13.5 million recorded in 2006 reflects the use of a 5.60% discount rate and an assumed 9.00% long-term rate of return on plan assets. The Company believes that these assumptions were, and that the resulting pension income amount was, reasonable. For purposes of comparison, using a discount rate of 5.35% in 2006 would have decreased the Company's pension income by $1.1 million. Had the assumed long-term rate of return on assets been 8.75%, the Company's pension income for 2006 would have been reduced by $2.1 million.

For 2006, the Company selected the discount rate of 5.60% which was derived using a cash flow matching technique. For 2007, the discount rate to be used will be 5.85%, which was derived using that same cash flow matching technique. The same discount rates were also selected for determination of other postemployment benefits costs discussed below.

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

The Company determines the fair value of substantially all of its pension assets utilizing market quotes rather than utilizing any

F-28

calculated values, "market related" values or other modeling techniques.

In developing the expected long-term rate of return assumptions, the Company evaluates input from actuaries and from pension fund investment consultants. Such consultants' 2006 review of the plan's historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 9.3%, 11.0%, 11.2% and 12.7%, respectively, all of which have been in excess of related broad indices. The 2006 expected long-term rate of return of 9.0% was based on a target asset allocation of 70% with equity managers and 30% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. For 2007, the expected rate of return will be 9.0%.

The pension trust is adequately funded, and no contributions have been required since 1997. Management does not anticipate the need to make pension contributions until after 2010.

Similar to its pension accounting, the Company follows SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," as amended by SFAS 158, in accounting for the cost of its postretirement medical and life insurance benefits. This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. The Company used a discount rate of 5.60% and recorded a net SFAS 106 cost of $22.3 million for 2006. Had the selected discount rate been 5.35%, the expense for 2006 would have been $0.5 million higher. Because the plan provisions include "caps" on company per capita costs, healthcare cost inflation rate assumptions do not materially impact the net expense recorded.

The Company also adopted the balance sheet recognition provisions of SFAS 158 effective December 31, 2006, as more fully described in Note 3 to the consolidated financial statements.

Asset Retirement Obligations

SFAS 143, "Accounting for Asset Retirement Obligations," together with Financial Accounting Standards Board Interpretation (FIN) 47, "Accounting for Conditional Asset Retirement Obligations," provides guidance for recording and disclosing liabilities related to future legally enforceable obligations to retire assets (ARO). SFAS 143 applies to the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation. Because such obligation relates primarily to the Company's regulated utility operations, SFAS 143 and FIN 47 have no significant impact on results of operations. As of December 31, 2006, the Company has recorded an ARO of $93 million for nuclear plant decommissioning (as discussed above) and an ARO of $199 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines. The ARO for nuclear plant decommissioning reflects a reduction of $46 million from the corresponding ARO recorded as of December 31, 2005. The reduction is primarily related to the expectation of lower decommissioning cost escalations than had been assumed in the prior cash flow analysis. All of the amounts recorded in connection with SFAS 143 and FIN 47 are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will 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 Company's utilities remains in place.

F-29

OTHER MATTERS

Off-Balance Sheet Transactions

Although SCANA invests in securities and business ventures, it does not hold investments in unconsolidated special purpose entities such as those described in SFAS 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," or as described in FIN 46(R), "Consolidation of Variable Interest 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 and equipment.

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 summarize 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 and weighted average interest rates and related maturities. Fair values for debt and swaps represent quoted market prices.

			Expected Maturity Date
December 31, 2006 Millions of dollars			2007	2008	2009	2010	2011	Thereafter	Total	Fair Value
Long-Term Debt:
	Fixed Rate ($)		33.2	123.2	108.2	14.8	619.3	2,023.6	2,922.3	3,020.0
		Average Fixed Interest Rate (%)	7.17	5.95	6.27	6.87	6.78	5.95	6.16
	Variable Rate ($)			100.0					100.0	100.2
		Average Variable Interest Rate (%)		5.52					5.52
Interest Rate Swaps:
	Pay Variable/Receive Fixed ($)		28.2	3.2	3.2	3.2	3.2	3.2	44.2	0.1
		Average Pay Interest Rate (%)	8.50	8.55	8.55	8.55	8.55	8.55	8.52
		Average Receive Interest Rate (%)	7.11	8.75	8.75	8.75	8.75	8.75	7.70

			Expected Maturity Date
December 31, 2005 Millions of dollars			2006	2007	2008	2009	2010	Thereafter	Total	Fair Value
Long-Term Debt:
	Fixed Rate ($)		174.4	68.6	158.6	143.6	43.6	2,524.6	3,113.4	3,108.8
		Average Fixed Interest Rate (%)	8.50	6.96	6.13	6.39	6.99	6.14	6.47
	Variable Rate ($)				100.0				100.0	100.0
		Average Variable Interest Rate (%)			4.56				4.56
Interest Rate Swaps:
	Pay Variable/Receive Fixed ($)		3.2	28.2	3.2	3.2	3.2	6.4	47.4	0.1
		Average Pay Interest Rate (%)	7.72	7.97	7.72	7.72	7.72	7.72	7.87
		Average Receive Interest Rate (%)	8.75	7.11	8.75	8.75	8.75	8.75	7.77

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 table excludes long-term debt of $80 million at December 31, 2006 and $97 million at December 31, 2005, which amounts do not have a stated interest rate associated with them.

Commodity Price Risk

The following table summarizes the Company's financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 DT. Fair value represents quoted market prices.

F-31

Expected Maturity:

	Futures Contracts			Options
	Futures Contracts			Purchased Call (Long)	Purchased Put (Short)	Sold Put (Long)
	Long	Short		Purchased Call (Long)	Purchased Put (Short)	Sold Put (Long)
2007
Settlement Price^(a)	6.76	6.57	Strike Price^(a)	9.08	10.89	6.17
Contract Amount^(b)	37.0	4.3	Contract Amount^(b)	2.7	1.4	1.2
Fair Value^(b)	28.8	3.0	Fair Value^(b)	0.1	—	(0.1	)
2008
Settlement Price^(a)	8.31	—	Strike Price^(a)	—	—	—
Contract Amount^(b)	10.3	—	Contract Amount^(b)	—	—	—
Fair Value^(b)	9.8	—	Fair Value^(b)	—	—	—

^(a): Weighted average, in dollars
^(b): Millions of dollars

Swaps		2007	2008	2009
Commodity Swaps:
	Pay fixed/receive variable^(b)	190.9	78.3	0.3
	Average pay rate^(a)	9.105	9.519	8.460
	Average received rate^(a)	6.948	8.475	8.447
	Fair Value^(b)	145.7	69.7	0.3
	Pay variable/receive fixed^(b)	0.9	0.8	—
	Average pay rate^(a)	7.333	8.111	—
	Average received rate^(a)	8.361	8.011	—
	Fair Value^(b)	1.1	0.8	—
Basis Swaps:
	Pay variable/receive variable^(b)	14.1	—	—
	Average pay rate^(a)	6.331	—	—
	Average received rate^(a)	6.319	—	—
	Fair Value^(b)	14.1	—	—

^(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 9 to the consolidated financial statements.

The NYMEX futures information above includes those financial positions of Energy Marketing, SCE&G and PSNC Energy. SCE&G's tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of these hedging activities are to be included in the PGA. As such, costs of related derivatives utilized by SCE&G to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. PSNC Energy utilizes futures, options and swaps to hedge gas purchasing activities. PSNC Energy's tariffs also include a provision for the recovery of actual gas costs incurred. PSNC Energy records premiums, transaction fees, margin requirements and any realized and unrealized 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.

F-32

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

SCANA Corporation:

We have audited the accompanying consolidated balance sheets of SCANA Corporation and subsidiaries (the "Company") as of December 31, 2006 and 2005, and the related consolidated statements of income, changes in common equity and comprehensive income, and of cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these 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 SCANA Corporation and subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans," effective December 31, 2006.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2007, expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

Columbia, South Carolina
February 28, 2007

F-33

SCANA Corporation
CONSOLIDATED BALANCE SHEETS

			December 31,
			2006			2005
			(Millions of dollars)
Assets
Utility Plant In Service			$	9,227		$	8,999
Accumulated Depreciation and Amortization				(2,815	)		(2,698	)

				6,412			6,301
Construction Work in Progress				326			175
Nuclear Fuel, Net of Accumulated Amortization				39			28
Acquisition Adjustments				230			230

	Utility Plant, Net			7,007			6,734

Nonutility Property and Investments:
	Nonutility property, net of accumulated depreciation of $70 and $62			132			108
	Assets held in trust, net-nuclear decommissioning			56			52
	Other investments			88			87

	Nonutility Property and Investments, Net			276			247

Current Assets:
	Cash and cash equivalents			201			62
	Receivables, net of allowance for uncollectible accounts of $14 and $25			655			881
	Receivables — affiliated companies			32			24
	Inventories (at average cost):
		Fuel		300			284
		Materials and supplies		93			79
		Emission allowances		22			54
	Prepayments and other			39			54
	Deferred income taxes			34			26

	Total Current Assets			1,376			1,464

Deferred Debits:
	Pension asset, net			200			303
	Emission allowances			27			—
	Regulatory assets			792			617
	Other			139			154

	Total Deferred Debits			1,158			1,074

		Total	$	9,817		$	9,519

F-34

			December 31,
			2006		2005
			(Millions of dollars)
Capitalization and Liabilities
Shareholders' Investment:
	Common equity		$	2,846	$	2,677
	Preferred stock (Not subject to purchase or sinking funds)			106		106

	Total Shareholders' Investment			2,952		2,783
Preferred Stock, Net (Subject to purchase or sinking funds)				8		8
Long-Term Debt, Net				3,067		2,948

	Total Capitalization			6,027		5,739

Current Liabilities:
	Short-term borrowings			487		427
	Current portion of long-term debt			43		188
	Accounts payable			414		471
	Accounts payable — affiliated companies			27		26
	Customer deposits and customer prepayments			85		70
	Taxes accrued			121		112
	Interest accrued			51		52
	Dividends declared			51		47
	Other			126		107

	Total Current Liabilities			1,405		1,500

Deferred Credits:
	Deferred income taxes, net			947		940
	Deferred investment tax credits			120		121
	Asset retirement obligations			292		322
	Postretirement benefits			194		148
	Regulatory liabilities			714		605
	Other			118		144

	Total Deferred Credits			2,385		2,280

Commitments and Contingencies (Note 10)				—		—

		Total	$	9,817	$	9,519

See Notes to Consolidated Financial Statements.

F-35

SCANA Corporation
CONSOLIDATED STATEMENTS OF INCOME

		Years Ended December 31,
		2006			2005			2004
		(Millions of dollars, except per share amounts)
Operating Revenues:
	Electric	$	1,877		$	1,909		$	1,688
	Gas — regulated		1,257			1,405			1,126
	Gas — nonregulated		1,429			1,463			1,071

	Total Operating Revenues		4,563			4,777			3,885

Operating Expenses:
	Fuel used in electric generation		615			618			467
	Purchased power		28			37			51
	Gas purchased for resale		2,213			2,399			1,753
	Other operation and maintenance		619			632			608
	Depreciation and amortization		333			510			265
	Other taxes		152			145			145

	Total Operating Expenses		3,960			4,341			3,289

Operating Income			603			436			596

Other Income (Expense):
	Other revenues		142			248			181
	Other expenses		(93	)		(200	)		(160	)
	Interest charges, net of allowance for borrowed funds used during construction of $8, $3 and $10		(209	)		(212	)		(202	)
	Gain (loss) on sale of investments and assets		3			9			(20	)
	Investment impairments		—			—			(27	)
	Preferred dividends of subsidiary		(7	)		(7	)		(7	)
	Allowance for equity funds used during construction		—			—			16

	Total Other Expense		(164	)		(162	)		(219	)

Income Before Income Taxes (Benefit) and Earnings (Losses) from Equity Method Investments and Cumulative Effect of Accounting Change			439			274			377
Income Tax Expense (Benefit)			119			(118	)		123

Income Before Earnings (Losses) from Equity Method Investments and Cumulative Effect of Accounting Change			320			392			254
Earnings (Losses) from Equity Method Investments			(16	)		(72	)		3
Cumulative Effect of Accounting Change, net of taxes			6			—			—

Net Income		$	310		$	320		$	257

Basic and Diluted Earnings Per Share of Common Stock:
Before Cumulative Effect of Accounting Change		$	2.63		$	2.81		$	2.30
Cumulative Effect of Accounting Change, net of taxes			.05			—			—

Basic and Diluted Earnings Per Share		$	2.68		$	2.81		$	2.30

Weighted Average Common Shares Outstanding (Millions)			115.8			113.8			111.6

See Notes to Consolidated Financial Statements.

F-36

SCANA Corporation
CONSOLIDATED STATEMENTS OF CASH FLOWS

				For the Years Ended December 31,
				2006			2005			2004
				(Millions of dollars)
Cash Flows From Operating Activities:
Net Income				$	310		$	320		$	257
Adjustments to reconcile net income to net cash provided from operating activities:
	Cumulative effect of accounting change, net of taxes				(6	)		—			—
	Excess losses (earnings), net of distributions from equity method investments				23			72			(3	)
	Depreciation and amortization				347			518			274
	Amortization of nuclear fuel				17			18			22
	(Gain) loss on sale of assets and investments				(3	)		(9	)		20
	Impairment of investments				—			—			27
	Hedging activities				(15	)		4			11
	Allowance for equity funds used during construction				—			—			(16	)
	Carrying cost recovery				(7	)		(11	)		—
	Cash provided (used) by changes in certain assets and liabilities:
		Receivables, net			218			(174	)		(225	)
		Inventories			(80	)		(188	)		(90	)
		Prepayments and other			(2	)		—			(2	)
		Pension asset			(13	)		(17	)		(14	)
		Other regulatory assets			(32	)		(28	)		(17	)
		Deferred income taxes, net			5			25			74
		Regulatory liabilities			9			(159	)		48
		Postretirement benefits obligations			(3	)		6			7
		Accounts payable			(77	)		79			91
		Taxes accrued			9			(20	)		23
		Interest accrued			(1	)		1			(4	)
	Changes in fuel adjustment clauses				3			(7	)		(3	)
	Changes in other assets				30			(17	)		22
	Changes in other liabilities				21			54			77

Net Cash Provided From Operating Activities					753			467			579

Cash Flows From Investing Activities:
	Utility property additions and construction expenditures, including debt AFC				(485	)		(366	)		(478	)
	Proceeds from sale of assets and investments				21			10			68
	Nonutility property additions				(42	)		(19	)		(23	)
	Investments				(25	)		(18	)		(20	)

Net Cash Used For Investing Activities					(531	)		(393	)		(453	)

Cash Flows From Financing Activities:
	Proceeds from issuance of common stock				79			84			65
	Proceeds from issuance of debt				132			221			136
	Repayments of debt				(156	)		(470	)		(169	)
	Redemption/repurchase of equity securities				—			(1	)		(4	)
	Dividends				(198	)		(181	)		(168	)
	Short-term borrowings, net				60			216			16

Net Cash Used For Financing Activities					(83	)		(131	)		(124	)

Net Increase (Decrease) in Cash and Cash Equivalents					139			(57	)		2
Cash and Cash Equivalents, January 1					62			119			117

Cash and Cash Equivalents, December 31				$	201		$	62		$	119

Supplemental Cash Flow Information:
	Cash paid for		— Interest (net of capitalized interest of $8, $3 and $10)	$	212		$	213		$	206
			— Income taxes		100			58			24
Noncash Investing and Financing Activities:
	Unrealized loss on securities available for sale, net of tax				—			—			(2	)
	Accrued construction expenditures				54			36			49

See Notes to Consolidated Financial Statements.

F-37

SCANA Corporation
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY AND COMPREHENSIVE INCOME

			Common Stock							Accumulated Other Comprehensive Income (Loss)
			Common Stock				Retained Earnings
			Shares	Amount			Retained Earnings						Total
			Millions
Balance as of December 31, 2003			111	$	1,187		$	1,113		$	6		$	2,306

Comprehensive Income:
	Net Income							257						257
	Changes in Other Comprehensive Income (Loss) net of taxes $(5)										(10	)		(10	)

		Total Comprehensive Income						257			(10	)		247
Issuance of Common Stock			2		65									65
Repurchase of Common Stock					(4	)								(4	)
Dividends Declared on Common Stock								(163	)					(163	)

Balance as of December 31, 2004			113		1,248			1,207			(4	)		2,451

Comprehensive Income (Loss):
	Net Income							320						320
	Changes in Other Comprehensive Income (Loss), net of taxes $—										—			—

		Total Comprehensive Income						320			—			320
Issuance of Common Stock			2		84									84
Dividends Declared on Common Stock								(178	)					(178	)

Balance as of December 31, 2005			115		1,332			1,349			(4	)		2,677

Comprehensive Income (Loss):
	Net Income							310						310
	Changes in Other Comprehensive Income (Loss), net of taxes $(8)										(14	)		(14	)

		Total Comprehensive Income						310			(14	)		296
Deferred Cost of Employee Benefit Plans, net of taxes $(7)											(11	)		(11	)
Issuance of Common Stock			2		79									79
Dividends Declared on Common Stock								(195	)					(195	)

Balance as of December 31, 2006			117	$	1,411		$	1,464		$	(29	)	$	2,846

The Company adopted SFAS 158 at December 31, 2006 and recorded in accumulated other comprehensive income certain gains, losses, prior service costs and credits that have not yet been recognized through net periodic benefit cost, net of tax effects.

See Notes to Consolidated Financial Statements.

F-38

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A. Organization and Principles of Consolidation

SCANA Corporation (SCANA, and together with its consolidated subsidiaries, the Company), 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 businesses and provides fiber optic communications in South Carolina.

The accompanying Consolidated Financial Statements reflect the accounts of SCANA, the following wholly-owned subsidiaries, and one other wholly-owned subsidiary in liquidation.

Regulated businesses
South Carolina Electric & Gas Company (SCE&G)
South Carolina Fuel Company, Inc. (Fuel Company)
South Carolina Generating Company, Inc. (GENCO)
Public Service Company of North Carolina, Incorporated (PSNC Energy)
Carolina Gas Transmission Corporation (CGTC)

Nonregulated businesses
SCANA Energy Marketing, Inc.
SCANA Communications, Inc. (SCI)
ServiceCare, Inc.
Primesouth, Inc.
SCANA Resources, Inc.
SCANA Services, Inc.
SCANA Corporate Security Services, Inc.

Effective November 1, 2006, CGTC began operating as an open access, transportation-only interstate pipeline company. CGTC resulted from the merger of SCG Pipeline, Inc. into South Carolina Pipeline Corporation (SCPC), both of which were wholly-owned subsidiaries of SCANA, and a subsequent name change.

The Company reports certain investments using the cost or equity method of accounting, as appropriate. Significant intercompany balances and transactions have been eliminated in consolidation except as permitted by Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation," which provides that profits on intercompany sales to regulated affiliates are not eliminated if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable.

B. Basis of Accounting

The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of SFAS 71, which requires cost-based rate-regulated utilities to 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 the regulatory assets and regulatory liabilities summarized as follows.

	December 31,
Millions of dollars	2006		2005
Regulatory Assets:
Accumulated deferred income taxes	$	174	$	177
Under-collections — electric fuel and gas cost adjustment clauses		95		61
Purchased power costs		9		17
Environmental remediation costs		29		28
Asset retirement obligations and related funding		264		250
Franchise agreements		55		56
Regional transmission organization costs		8		11
Deferred employee benefit plan costs		142		—
Other		16		17

Total Regulatory Assets	$	792	$	617

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Regulatory Liabilities:
Accumulated deferred income taxes	$	38	$	39
Over-collections-electric fuel and gas cost adjustment clauses		8		20
Other asset removal costs		599		488
Storm damage reserve		44		38
Planned major maintenance		6		9
Other		19		11

Total Regulatory Liabilities	$	714	$	605

Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.

Under- and over-collections — electric fuel and gas cost adjustment clauses, net, represent amounts under- or over-collected from customers pursuant to the fuel adjustment clause (electric customers) or gas cost adjustment clause (gas customers) as approved by the Public Service Commission of South Carolina (SCPSC) or North Carolina Utilities Commission (NCUC) during annual hearings. Included in these amounts are regulatory assets or liabilities arising from the natural gas hedging programs of the Company's regulated operations. See Notes 1E and 1L.

Purchased power costs represents costs necessitated by outages at two of SCE&G's base load generating plants in winter 2000-2001. The SCPSC approved recovery of these costs in base rates over a three-year period beginning January 2005.

Environmental remediation costs represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by the Company. Costs incurred at sites owned by SCE&G are being recovered through rates, of which approximately $17.9 million remain to be recovered. Through June 30, 2006, PSNC Energy incurred and deferred $3.6 million in costs, net of insurance settlements, that were not being recovered through rates. In connection with an October 2006 NCUC rate order, such costs are now being recovered through rates over a three-year period. In addition, management believes that costs incurred subsequent to June 30, 2006, totaling $0.9 million at December 31, 2006, and the estimated remaining costs of $6.9 million, will be recoverable by PSNC Energy through rates.

Asset retirement obligations (ARO) and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle V. C. Summer Nuclear Station (Summer Station) and conditional AROs recorded as required by SFAS 143, "Accounting for Asset Retirement Obligations," and Financial Accounting Standards Board Interpretation (FIN) 47, "Accounting for Conditional Asset Retirement Obligations."

Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. SCE&G is amortizing these amounts through cost of service rates over approximately 20 years.

Regional transmission organization costs represent costs incurred by SCE&G in the United States Federal Energy Regulatory Commission (FERC)-mandated formation of GridSouth. The project was suspended in 2002. Effective January 2005, the SCPSC approved the amortization of these amounts through cost of service rates over approximately five years.

Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities under provisions of SFAS 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans," but

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which are expected to be recovered through utility rates (see Note 3).

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

The storm damage reserve represents an SCPSC-approved reserve account for SCE&G capped at $50 million to be collected through rates. The accumulated reserve can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. During the years ended December 31, 2006 and 2005, no significant amounts were drawn from this reserve account.

Planned major maintenance related to certain fossil and hydro-turbine equipment and nuclear refueling outages is accrued in advance of the time the costs are incurred, as approved through specific SCPSC orders. SCE&G is allowed to collect $8.5 million annually over an eight-year period through electric rates to offset turbine maintenance expenditures. Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service and do not receive special rate consideration.

The SCPSC and the NCUC (collectively, state commissions) have reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by a state commission. In recording these 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. However, ultimate recovery is subject to state commission approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company's results of operations, liquidity or financial position in the period the write-off would be recorded.

C. Utility Plant and Major Maintenance

Utility plant is stated substantially at original cost. The costs of additions, renewals and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and an allowance for funds used during construction, 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, replacements and renewals 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 maintenance expense.

SCE&G, operator of Summer Station, and the South Carolina Public Service Authority (Santee Cooper) jointly own Summer Station in the proportions of two-thirds and one-third, respectively. The parties share the operating costs and energy output of the plant in these proportions. Each party, however, provides its own financing. Plant-in-service related to SCE&G's portion of Summer Station was $1.0 billion as of December 31, 2006 and 2005 (including amounts related to ARO). Accumulated depreciation associated with SCE&G's share of Summer Station was $496.8 million and $478.7 million as of December 31, 2006 and 2005, respectively (including amounts related to ARO). SCE&G's share of the direct expenses associated with operating Summer Station is included in other operation and maintenance expenses and totaled $77.7 million for 2006, $76.3 million for 2005 and $74.5 million for 2004.

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Planned major maintenance related to certain fossil and hydro turbine equipment and nuclear refueling outages is accrued in advance of the time the costs are actually incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. Other planned major maintenance is expensed when incurred. Beginning in 2005, SCE&G is collecting $8.5 million annually over an eight-year period through electric rates to offset turbine maintenance expenditures. For the year ended December 31, 2006, SCE&G incurred $7.2 million for turbine maintenance. The remaining $1.3 million is in a regulatory liability account on the balance sheet. Nuclear refueling outages are scheduled 18 months apart, and SCE&G begins accruing for each successive outage upon completion of the preceding outage. SCE&G accrued $1.0 million per month from July 2005 through December 2006 for its portion of the outage in October 2006 and is accruing $1.1 million per month for its portion of the outage scheduled for the spring of 2008. Total costs for the 2006 outage were $25.5 million, of which SCE&G was responsible for $17.0 million. As of December 31, 2006 and 2005, SCE&G had accrued $0.2 million and $5.7 million, respectively.

D. Allowance for Funds Used During Construction (AFC)

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 composite rates of 5.5%, 4.9% and 6.9% for 2006, 2005 and 2004, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.

E. Revenue Recognition

The Company records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered, but not yet billed. Unbilled revenues totaled $177.6 million at December 31, 2006 and $280.9 million at December 31, 2005.

Fuel costs for electric generation are collected through the fuel cost component in retail electric rates. This component is established by the SCPSC during annual fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is deferred and included when determining the fuel cost component during the next annual hearing. SCE&G had undercollected through the electric fuel cost component $28.9 million and $44.1 million at December 31, 2006 and 2005, respectively, which amounts are included in other regulatory assets.

Customers subject to the gas cost adjustment clause are billed based on a fixed cost of gas determined by the state commission during annual gas cost recovery hearings. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during the next annual hearing. At December 31, 2006 and 2005, SCE&G had undercollected $20.3 million and $11.8 million, respectively, which amounts are also included in other regulatory assets. At December 31, 2006 and 2005, PSNC Energy had undercollected $38.5 million, net, and overcollected $15.1 million, net, respectively, which amounts are included in other regulatory assets or liabilities.

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SCE&G's and PSNC Energy's gas rate schedules for residential, small commercial and small industrial customers include a weather normalization adjustment which minimizes fluctuations in gas revenues due to abnormal weather conditions.

F. Depreciation and Amortization

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:

	2006		2005		2004
SCE&G	3.19	%	3.20	%	2.99	%
GENCO	2.66	%	2.66	%	2.66	%
CGTC	2.04	%	2.01	%	2.04	%
PSNC Energy	3.69	%	3.77	%	3.87	%
Aggregate of Above	3.19	%	3.20	%	3.04	%

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 United States Department of Energy (DOE) under a contract for disposal of spent nuclear fuel.

The Company considers amounts categorized by FERC as "acquisition adjustments" to be goodwill as defined in SFAS 142, "Goodwill and Other Intangible Assets," and has ceased amortization of such amounts. These amounts are related to acquisition adjustments of approximately $466 million ($210 million net of accumulated amortization) recorded by PSNC Energy (Gas Distribution segment) and approximately $40 million ($20 million net of accumulated amortization) recorded by CGTC (Gas Transmission segment). In accordance with SFAS 142, the Company performs an annual impairment evaluation of its investment in PSNC Energy and CGTC. These calculations have indicated no need for further write-downs of acquisition adjustments. Should a write-down be required in the future, such a charge would be treated as an operating expense.

G. Nuclear Decommissioning

SCE&G's two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $451.0 million, stated in 2006 dollars, based on a decommissioning study completed in 2006. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station. The cost estimate assumes that the site would be maintained over a period of 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 2006, 2005 and 2004) 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 on proceeds, 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.

H. Income and Other 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

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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.

The Company records excise taxes billed and collected, as well as local franchise and similar taxes, as liabilities until they are remitted to the respective taxing authority. Accordingly, no such taxes are included in revenues or expenses in the statements of income.

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

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

J. 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. 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. Such amounts are recorded in deferred debits and amortized with recovery provided through rates.

K. 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, treasury bills and notes.

L. Commodity Derivatives

The Company records derivatives contracts at their fair value in accordance with SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, and adjusts fair value each reporting period. The Company determines fair value of most of the energy-related derivatives contracts using quotations from markets where they are actively traded. For other derivatives contracts, the Company uses published market surveys and, in certain cases, independent parties to obtain quotes concerning fair value. Market quotes tend to be more plentiful for those derivatives contracts maturing in two years or less. The Company's derivatives contracts do not extend beyond two years. See Note 9.

The Company's regulated gas operations (SCE&G and PSNC Energy) hedge gas purchasing activities using over-the-counter options and swaps and New York Mercantile Exchange (NYMEX) futures and options. SCE&G's tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of these hedging activities are to be included in the PGA. As such, costs of related derivatives utilized to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value

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of these derivatives is recorded as a regulatory asset or liability. PSNC Energy's tariffs also include a provision for the recovery of actual gas costs incurred. PSNC Energy records premiums, transaction fees, margin requirements and any realized and unrealized 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.

M. New Accounting Matters

SFAS 123 (revised 2004), "Share-Based Payment," (SFAS 123(R)) requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, 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. SFAS 123(R) replaced SFAS 123, "Accounting for Stock-Based Compensation," and superseded Accounting Principles Board (APB) Opinion 25, "Accounting for Stock Issued to Employees." The Company adopted SFAS 123(R) in the first quarter of 2006. The impact on the Company's results of operations is discussed at Note 3.

The Company adopted SFAS 154, "Accounting Changes and Error Corrections," in the first quarter of 2006. SFAS 154 requires retrospective application to financial statements of prior periods for every voluntary change in accounting principle unless such retrospective application is impracticable. SFAS 154 replaces APB 20, "Accounting Changes," and SFAS 3, "Reporting Accounting Changes in Interim Financial Statements." The adoption of SFAS 154 had no impact on the Company's results of operations, cash flows or financial position.

SFAS 157, "Fair Value Measurements," was issued in September 2006. SFAS 157 establishes a framework for measuring fair value to increase the consistency and comparability in fair value measurements. The Company will adopt SFAS 157 in the first quarter of 2008, and does not expect that the initial adoption will have a material impact on the Company's results of operations, cash flows or financial position.

In September 2006, SFAS 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans," amended SFAS 87 and SFAS 106 to require recognition of the overfunded or underfunded status of pension and other postretirement benefit plans on the balance sheet. Under SFAS 158, gains and losses, prior service costs and credits, and any remaining transition amounts under SFAS 87 and SFAS 106 that have not yet been recognized through net periodic benefit cost are to be recognized in accumulated other comprehensive income, net of tax effects, until they are amortized as a component of net periodic cost. The Company adopted SFAS 158 as of December 31, 2006. Because a significant amount of the Company's pension and other postretirement costs recorded under SFAS 87 and SFAS 106 are attributable to employees in its regulated operations, the adoption of SFAS 158 primarily resulted in the recording of additional regulatory assets. The impact of adoption on the Company's financial position is detailed at Note 3. The adoption did not have an impact on the Company's results of operations or cash flows.

SFAS 159, "The Fair Value Option for Financial Assets and Financial Liabilities," was issued in February 2007. SFAS 159 allows entities to measure at fair value many financial instruments and certain other assets and liabilities that are not otherwise required to be measured at fair value. SFAS 159 is effective for fiscal years beginning after November 15, 2007.

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The Company has not determined what impact, if any, that adoption will have on the Company's results of operations, cash flows or financial position.

FIN 48, "Accounting for Uncertainty in Income Taxes," was issued in June 2006. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with SFAS 109,"Accounting for Income Taxes." FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company will adopt FIN 48 in the first quarter of 2007, and does not expect that the initial adoption will have a material impact on the Company's results of operations, cash flows or financial position.

FASB Staff Position (FSP) AUG AIR-1 "Accounting for Planned Major Maintenance Activities," was issued in September 2006, and amends APB 28, "Interim Financial Reporting," to prohibit the use of the accrue-in-advance method of accounting for planned major maintenance. As disclosed in Note 1A, the Company has received specific SCPSC orders providing for use of accrue-in-advance accounting for certain planned major maintenance activities. Accordingly, the Company will follow SFAS 71 when accounting for these activities. The Company will adopt FSP AUG AIR-1 in the first quarter of 2007, and does not expect that the initial adoption will have a material impact on the Company's results of operations, cash flows or financial position.

The United States Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin 108 (SAB 108) in September 2006. SAB 108 provides guidance on the consideration of the effects of prior year misstatements in quantifying and assessing the materiality of current year misstatements. SAB 108 also provides transition guidance for correcting errors existing from prior years. The Company adopted SAB 108 in December 2006. The adoption had no impact on the Company's results of operations, cash flows or financial position.

N. Earnings Per Share

Earnings per share amounts have been computed in accordance with SFAS 128, "Earnings Per Share." Under SFAS 128, basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share are computed by dividing net income by the weighted average number of shares of common stock outstanding during the period, after giving effect to securities considered to be dilutive potential common stock. The Company uses the treasury stock method in determining total dilutive potential common stock. The Company has no securities that would have an antidilutive effect on earnings per share.

O. Transactions with Affiliates

SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel. SCE&G had recorded as receivables from these affiliated companies approximately $31.8 million and $24.6 million at December 31, 2006 and 2005, respectively. SCE&G had recorded as payables to these affiliated companies approximately $26.6 million and $25.3 million at December 31, 2006 and 2005, respectively. SCE&G purchased approximately $291.1 million, $248.1 million and $190.6 million of synthetic fuel from these affiliated companies in 2006, 2005 and 2004, respectively.

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The Company received cash distributions from equity investees of $6.7 million in 2006, $7.1 million in 2005 and $7.3 million in 2004. The Company made cash investments in equity investees of $18.4 million in 2006, $17.7 million in 2005 and $18.7 million in 2004.

P. 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.

2. RATE AND OTHER REGULATORY MATTERS

SCE&G

Electric

In a January 2005 order, the SCPSC granted SCE&G a composite increase in retail electric rates of 2.89%, designed to produce additional annual revenues of $41.4 million based on a test year calculation. The SCPSC lowered SCE&G's allowed return on common equity from 12.45% to an amount not to exceed 11.4%, with rates set at 10.7%. The new rates became effective in January 2005. As part of its order, the SCPSC approved SCE&G's recovery of construction and operating costs for SCE&G's new Jasper County Electric Generating Station, recovery of costs of mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and, beginning in January 2005, the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray. Under the accounting methodology approved by the SCPSC, construction costs related to the Lake Murray back-up dam project were recorded in a special dam remediation account outside of rate base, and depreciation is being recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.

In the January 2005 order, the SCPSC also approved recovery over a five-year period of SCE&G's $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization and recovery through base rates over three years of $25.6 million of purchased power costs that were previously deferred. As a part of its order, the SCPSC extended through 2010 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station up to $36 million annually without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the immediately following year. No such additional depreciation was recognized in 2006, 2005 or 2004.

SCE&G's rates are established using a cost of fuel component approved by the SCPSC which may be modified periodically to reflect changes in the price of fuel purchased by SCE&G. SCE&G's cost of fuel component in effect during 2006 and 2005 was as follows:

Rate Per KWh		Effective Date
$.01764		January-April 2005
$.02256		May 2005-April 2006
$.02516		May-December 2006

In connection with the May 2006 fuel component increase, SCE&G agreed to spread

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the recovery of previously undercollected fuel costs of $38.5 million over a two-year period.

Gas

In October 2005, the SCPSC granted SCE&G an overall increase of $22.9 million, or 5.69%, in retail gas base rates. The new rates are based on an allowed return on common equity of 10.25%, and became effective with the first billing cycle in November 2005.

In June 2006, SCE&G reported to the SCPSC that its return on common equity for the twelve months ended March 31, 2006 was more than 0.5% below the allowed return, and as provided under South Carolina's Natural Gas Rate Stabilization Act, SCE&G requested an annualized increase in certain natural gas base rates. In September 2006, the SCPSC approved an annual increase of $17.4 million. The rate adjustment was effective with the first billing cycle in November 2006.

SCE&G's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by SCE&G. SCE&G's cost of gas components by class were as follows (rate per therm):

Effective Date	Residential		Small/Medium		Large
January-October 2005	$	.903	$	.903	$	.903
November 2005		1.297		1.222		1.198
December 2005		1.362		1.286		1.263
January 2006		1.297		1.222		1.198
February-October 2006		1.227		1.152		1.128
November 2006		1.115		1.004		.963
December 2006		1.240		1.130		1.090

In October 2006, the SCPSC approved a reduction in the cost of gas component of SCE&G's retail natural gas rates, effective with the first billing cycle of November 2006. The SCPSC also authorized SCE&G to adjust its cost of gas on a monthly, rather than an annual, basis beginning in December 2006.

Prior to November 2005, the SCPSC allowed SCE&G to recover through a billing surcharge to its gas customers the costs of environmental clean-up at the sites of former MGPs. Effective with the first billing cycle of November 2005, the billing surcharge was eliminated. In its place, SCE&G defers certain MGP environmental costs in regulatory asset accounts and collects and amortizes these costs through base rates.

PSNC Energy

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

PSNC Energy's benchmark cost of gas was as follows:

Rate Per Therm		Effective Date
$	.825	January 2005
	.725	February-July 2005
	.825	August-September 2005
	1.100	October 2005
	1.275	November-December 2005
	1.075	January 2006
	.875	February 2006
	.825	March-December 2006

In January 2007, the NCUC approved PSNC Energy's request to decease the benchmark cost of gas from $0.825 per therm to $0.750 per therm for service rendered on and after January 1, 2007.

In October 2006, the NCUC granted PSNC Energy an annual increase in retail natural gas

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margin revenues of approximately $15.2 million, or 2.6%, which was offset by a $9.2 million decrease in fixed-gas cost revenues, for an overall increase of $6 million, or 1.0%. The new rates are based on an allowed overall rate of return of 8.9%, and became effective with the first billing cycle in November 2006. In connection with the rate increase, the NCUC approved PSNC Energy's recovery through rates, over a three-year period, of certain costs for environmental remediation and pipeline integrity management.

In September 2006, in connection with PSNC Energy's 2006 Annual Prudence Review, the NCUC determined that PSNC Energy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the twelve-month review ended March 31, 2006.

In March 2006, the NCUC authorized PSNC Energy to place present and future pipeline supplier refunds into the appropriate deferred accounts for the over- or under-recovery of gas costs. Prior refunds from PSNC Energy's interstate pipeline transporters had been placed in a state-approved expansion fund to provide financing for expansion into areas that otherwise would not be economically feasible to serve. In December 2006, PSNC Energy received a disbursement of $1.1 million from the state expansion fund upon completion of a project to expand natural gas service to Louisburg, North Carolina.

In November 2005, the NCUC authorized an amendment to PSNC Energy's Rider D rate mechanism allowing recovery of certain uncollectible expenses related to gas cost. This change was effective December 1, 2005.

CGTC

In July 2006, FERC approved the application for merger of SCG Pipeline, Inc., into SCPC. On November 1, 2006, the merger was finalized, SCPC was renamed CGTC and CGTC commenced operations as an open access transportation-only interstate pipeline company.

3. 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 permanent employees. The Company's policy has been to fund the plan to the extent permitted by applicable federal income tax regulations as determined by an independent actuary.

Effective July 1, 2000 the Company's pension plan, which provided a final average pay formula, was amended to provide a cash balance formula for employees hired before January 1, 2000 who elected that option and for all employees hired on or after January 1, 2000. For employees who elected to remain under the final average pay formula, benefits are based on years of credited service and the employee's average annual base earnings received during the last three years of employment. For employees under the cash balance formula, benefits accumulate as a result of compensation credits and interest credits.

In addition to pension benefits, the Company provides certain unfunded postretirement health care and life insurance benefits to active and retired employees. Retirees share in a portion of their medical care cost. The Company provides life insurance benefits to retirees at no charge. 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.

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The Company adopted the balance sheet recognition provisions of SFAS 158 at December 31, 2006. The incremental effect of applying SFAS 158 on individual line items in the balance sheet was as follows:

December 31, 2006	Before Application of SFAS 158		Adjustments			After Application of SFAS 158
	Millions of dollars
Deferred debits — pension asset, net	$	316.7	$	(117.2	)	$	199.5
Deferred debits — regulatory assets		649.9		142.4			792.3
Deferred debits — other		137.9		1.6			139.5
Total deferred debits		1,131.2		26.8			1,158.0
Total assets		9,790.2		26.8			9,817.0
Common equity		2,855.8		(9.8	)		2,846.0
Total shareholders' investment		2,962.0		(9.8	)		2,952.2
Total capitalization		6,036.5		(9.8	)		6,026.7
Current liabilities — other		112.2		13.7			125.9
Total current liabilities		1,391.5		13.7			1,405.2
Deferred credits — deferred income taxes, net		953.1		(6.4	)		946.7
Deferred credits — postretirement benefits		158.2		35.8			194.0
Deferred credits — other		124.8		(6.5	)		118.3
Total deferred credits		2,362.1		22.9			2,385.0
Total capitalization and liabilities		9,790.2		26.8			9,817.0

Funded Status

The funded status at the end of the year and the related amounts recognized on the balance sheets follow:

	Pension Benefits December 31,				Other Postretirement Benefits December 31,
Millions of Dollars	2006		2005		2006			2005
Fair value of plan assets	$	912.5	$	854.3		—			—
Benefit obligations		713.0		711.4	$	206.9		$	202.1

Funded status		199.5		142.9		(206.9	)		(202.1	)
Unrecognized net actuarial loss		n/a		88.4		n/a			44.4
Unrecognized prior service cost		n/a		71.3		n/a			5.2
Unrecognized transition obligation		n/a		0.6		n/a			4.3

Amount recognized, end of year	$	199.5	$	303.2	$	(206.9	)	$	(148.2	)

Amounts recognized on the balance sheets consist of:

	Pension Benefits December 31,				Other Postretirement Benefits December 31,
Millions of Dollars	2006		2005		2006			2005
Noncurrent asset	$	199.5		n/a		—			n/a
Current liability		—		n/a	$	(12.9	)		n/a
Noncurrent liability		—		n/a		(194.0	)		n/a
Prepaid benefit cost		n/a	$	303.2		n/a			n/a
Accrued benefit cost		n/a		—		n/a		$	(148.2	)

Deferred amounts recognized in accumulated other comprehensive income (a component of common equity) as of December 31, 2006, including the adjustment above to reflect the adoption of SFAS 158, were as follows:

December 31, 2006	Pension Benefits		Other Postretirement Benefits		Total
	Millions of dollars
Transition Obligation		—	$	0.6	$	0.6
Prior Service Costs	$	0.9		0.6		1.5
Actuarial Losses		6.6		2.4		9.0

Total	$	7.5	$	3.6	$	11.1

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The estimated transition obligation, prior service costs and actuarial losses for the defined benefit plans that will be amortized from accumulated other comprehensive income into net periodic benefit costs during 2007 are less than $300,000 in aggregate.

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

	Retirement Benefits						Other Postretirement Benefits
Millions of dollars	2006			2005			2006			2005
Benefit obligation, January 1	$	711.5		$	669.5		$	202.1		$	197.5
Service cost		14.0			12.2			4.6			3.5
Interest cost		39.8			38.3			11.5			10.7
Plan participants' contributions		—			—			2.1			2.3
Plan amendments		0.6			—			4.0			(0.3	)
Actuarial (gain) loss		(14.4	)		27.1			(5.5	)		1.5
Benefits paid		(38.5	)		(35.6	)		(11.9	)		(13.1	)

Benefit obligation, December 31	$	713.0		$	711.5		$	206.9		$	202.1

The accumulated benefit obligation for retirement benefits at the end of 2006 and 2005 was $666.6 million and $664.4 million, respectively. These accumulated retirement benefit obligations differ from the projected retirement benefit obligations above in that they reflect no assumptions about future compensation levels.

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

		2006		2005
Annual discount rate used to determine benefit obligations		5.85	%	5.60	%
Assumed annual rate of future salary increases for projected benefit obligation		4.00	%	4.00	%

A 9.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2006. The rate was assumed to decrease gradually to 5.0% for 2013 and to remain at that level thereafter. The effects of a one percentage point increase or decrease in the assumed healthcare cost trend rate on the accumulated other postretirement benefit obligation for health care benefits are as follows:

Millions of dollars		1% Increase			1% Decrease
Effect on postretirement benefit obligation		$	3.1		$	(2.7	)

Changes in Plan Assets

	Retirement Benefits
Millions of dollars	2006			2005
Fair value of plan assets, January 1	$	854.3		$	846.7
Actual return on plan assets		96.7			43.2
Benefits paid		(38.5	)		(35.6	)

Fair value of plan assets, December 31	$	912.5		$	854.3

The Company determines the fair value of substantially all of its pension assets utilizing market quotes rather than utilizing any calculated values, "market related" values or other modeling techniques. At the end of 2006 and 2005, the fair value of plan assets for the pension plan exceeded both the projected benefit obligation and the accumulated benefit obligation discussed above.

In connection with the joint ownership of Summer Station, as of December 31, 2006 and 2005, the Company recorded within deferred

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credits a $3.6 million and $10.2 million obligation, respectively, to Santee Cooper, representing an estimate of the net pension asset attributable to the Company's contributions to the pension plan that were recovered through billings to Santee Cooper for its one-third portion of shared costs. As of December 31, 2006 and 2005, the Company also recorded within deferred debits a $9.9 million and $7.1 million receivable, respectively, from Santee Cooper, representing an estimate of its portion of the unfunded net postretirement benefit obligation.

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, respectively, are as follows:

			Other Postretirement Benefits*
Expected Benefit Payments Millions of dollars	Pension Benefits		Excluding Medicare Subsidy		Including Medicare Subsidy
2007	$	39.7	$	13.3	$	12.9
2008		40.1		13.6		13.2
2009		40.5		13.6		13.2
2010		40.9		14.1		13.7
2011		41.3		14.3		13.9
2012-2016		212.8		76.2		74.2

* Net of participant contributions

Net Periodic Benefit Cost (Income)

As allowed by SFAS 87 and SFAS 106, as amended, the Company records net periodic benefit cost (income) utilizing beginning of the year assumptions. Disclosures required for these plans under SFAS 132, "Employer's Disclosures about Pensions and Other Postretirement Benefits," as amended, are set forth in the following tables.

Components of Net Periodic Benefit Cost (Income)

	Retirement Benefits									Other Postretirement Benefits
Millions of dollars	2006			2005			2004			2006		2005		2004
Service cost	$	14.0		$	12.2		$	11.1		$	4.6	$	3.5	$	3.3
Interest cost		39.8			38.3			37.4			11.5		10.7		11.4
Expected return on assets		(75.2	)		(76.3	)		(71.0	)		n/a		n/a		n/a
Prior service cost amortization		6.8			6.9			6.6			1.1		0.8		1.4
Amortization of actuarial loss		0.5			—			—			1.7		1.2		1.9
Transition amount amortization		0.6			0.8			0.8			0.8		0.8		0.8

Net periodic benefit (income) cost	$	(13.5	)	$	(18.1	)	$	(15.1	)	$	19.7	$	17.0	$	18.8

Significant Assumptions Used in Determining Net Periodic Benefit Cost (Income)

	Retirement Benefits						Other Postretirement Benefits
	2006		2005		2004		2006		2005		2004
Discount rate	5.60	%	5.75	%	6.00	%	5.60	%	5.75	%	6.00	%
Expected return on plan assets	9.00	%	9.25	%	9.25	%	n/a		n/a		n/a
Rate of compensation increase	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%
Health care cost trend rate	n/a		n/a		n/a		9.00	%	9.00	%	9.50	%
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		2012		2011		2011

The effect of a one-percentage-point increase or decrease in the assumed health care cost trend rate on total service and interest cost is less than $250,000.

Pension Plan Contributions

The pension trust is adequately funded. No contributions have been required since 1997, and the Company does not anticipate making contributions to the pension plan until after 2010.

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Pension Plan Asset Allocations

The Company's pension plan asset allocation at December 31, 2006 and 2005 and the target allocation for 2007 are as follows:

Asset Category	Target Allocation		Percentage of Plan Assets At December 31,
	2007		2006		2005
Equity Securities	70	%	72	%	72	%
Debt Securities	30	%	28	%	28	%

The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the actuarial accrued liability for the pension plan, (2) maximizing return within reasonable and prudent levels of risk in order to minimize contributions, and (3) maintaining sufficient liquidity to meet benefit payment obligations on a timely basis. The pension plan operates with several risk and control procedures, including ongoing reviews of liabilities, investment objectives, investment managers and performance expectations. Transactions involving certain types of investments are prohibited. Equity securities held by the pension plan during the above periods did not include SCANA common stock.

In developing the expected long-term rate of return assumptions, management evaluates the pension plan's historical cumulative actual returns over several periods, all of which returns have been in excess of related broad indices. The expected long-term rate of return of 9.0% assumes an asset allocation of 70% with equity managers and 30% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. For 2007, the expected rate of return also will be 9.0%.

Share-Based Compensation

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

SFAS 123(R) requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, 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. The cumulative effect of the adoption of SFAS 123(R) on January 1, 2006 resulted in a $.05 per share (net of taxes) gain in the first quarter of 2006 based on a reduction of prior compensation accruals for performance awards (discussed below) granted in 2004 and 2005.

Liability Awards

Through 2006, certain executives were granted a target number of performance shares on an annual basis that vest over a three-year period. Each performance share has a value that is equal to, and changes with, the value of a share of SCANA common stock, and dividend equivalents are accrued on, and reinvested in, the performance shares. Payout of performance share awards is determined by SCANA's performance against pre-determined measures of total shareholder return (TSR) as compared to a peer group of utilities (weighted 60%) and growth in earnings per share (as defined) (weighted 40%) over the three year plan cycle. TSR is calculated by dividing stock price change over the three-year period, plus cash dividends, by the stock price as of the beginning of the period. Payouts vary according to SCANA's ranking against the peer group and

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relative earnings per share projection achievement. Awards are designated as target shares of SCANA common stock and may be paid in stock or cash or a combination of stock and cash at SCANA's discretion.

Under SFAS 123(R) compensation cost of these liability awards is recognized over the three-year performance period 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. Cash-settled liabilities totaling $6.4 million were paid during the twelve months ended December 31, 2006. No such payments were made in 2005.

Fair value adjustments for performance awards resulted in a reduction to compensation expense recognized in the statements of income, exclusive of the cumulative effect adjustment discussed previously, totaling $(6.5) million for the year ended December 31, 2006, and increases to compensation expense totaling $3.6 million and $13.0 million for the years ended December 31, 2005 and 2004, respectively. Fair value adjustments resulted in a net credit to capitalized compensation costs of approximately $(0.8) million during the year ended December 31, 2006, compared to capitalized costs of approximately $0.4 million in 2005 and $1.4 million in 2004.

Equity Awards

A summary of activity related to nonqualified stock options since December 31, 2003 follows:

	Number of Options		Weighted Average Exercise Price
Outstanding — December 31, 2003	1,493,685		$	27.39
Exercised	(751,997	)	$	26.28
Forfeited	(11,241	)	$	27.52

Outstanding — December 31, 2004	730,447		$	27.49
Exercised	(291,177	)	$	27.48
Forfeited	—			—

Outstanding — December 31, 2005	439,270		$	27.53
Exercised	(53,330	)	$	27.52
Forfeited	—			—

Outstanding — December 31, 2006	385,940		$	27.56

No stock options have been granted since August 2002, and all options were fully vested in August 2005. The options expire ten years after the grant date. At December 31, 2006, all outstanding options were currently exercisable at prices ranging from $25.50-$29.60, and had a weighted-average remaining contractual life of 4.9 years.

All options were granted with exercise prices equal to the fair market value of SCANA's common stock on the respective grant dates; therefore, no compensation expense was recognized in connection with such grants. If the Company had recognized compensation expense for the issuance of options based on the fair value method described in SFAS 123(R), pro forma net income and earnings per share would have been unchanged from that reported for the years ended December 31, 2005 and 2004.

The exercise of stock options during the period was satisfied using original issue shares of the Company's common stock. The Company

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realized $1.5 million, $8.0 million and $20.5 million in cash upon the exercise of options in the years ended December 31, 2006, 2005 and 2004, respectively. In addition, tax benefits resulting from the exercise of those stock options totaling $0.3 million, $1.3 million and $2.4 million were credited to additional paid in capital in these periods.

Beginning in 2007, the Company will satisfy the exercise of stock options using open market purchases of common stock. The Company estimates that 200,000 common shares will be repurchased in 2007 due to the exercise of stock options.

4. LONG-TERM DEBT

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

			December 31,
	Weighted-Average Interest Rate	Maturity Date	December 31,
	Weighted-Average Interest Rate	Maturity Date	2006			2005
			Millions of dollars
Medium-Term Notes (unsecured)^(a)	6.40%	2007-2012	$	940		$	940
First Mortgage Bonds (secured)	6.00%	2009-2036		1,675			1,550
First & Refunding Mortgage Bonds (secured)	9.00%	2006		—			131
GENCO Notes (secured)	5.92%	2011-2024		123			127
Industrial and Pollution Control Bonds	5.24%	2012-2032		156			156
Senior Debentures^(b)	7.47%	2012-2026		119			122
Fair value of interest rate swaps^(c)				21			25
Other		2007-2014		89			107

Total debt				3,123			3,158
Current maturities of long-term debt				(43	)		(188	)
Unamortized Discount				(13	)		(22	)

Total long-term debt, net			$	3,067		$	2,948

^(a): In 2006, includes $100.0 million of variable interest debt and $25.0 million of fixed rate debt hedged by a variable interest rate swap.
^(b): In 2006, includes $19.2 million of fixed rate debt hedged by a variable interest rate swap.
^(c): In 2006, includes $20.7 million representing unamortized payments received to terminate previous swaps. See discussion at Note 9.

The annual amounts of long-term debt maturities for the years 2007 through 2011 are summarized as follows:

Year	Millions of dollars
2007	$	43
2008		232
2009		143
2010		21
2011		625

Under an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT), SCE&G borrowed an aggregate $59 million from the Bank to construct a roadbed for SCDOT in connection with the Lake Murray back-up dam project. Such borrowings are being repaid interest-free over ten years. At December 31, 2006 and 2005, SCE&G had $44.3 million and $50.2 million outstanding under the agreement, respectively.

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

5. LINES OF CREDIT AND SHORT-TERM BORROWINGS

Details of lines of credit at December 31, 2006 and 2005, are as follows:

Millions of dollars			2006		2005
Lines of credit (total and unused)
	Committed:
		Short-term	$	—	$	350
		Long-term		1,100		650
	Uncommitted^(a)			103		103

^(a): SCANA or SCE&G may use $78 million of these lines of credit.

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Bank loans and commercial paper outstanding (270 or fewer days) at December 31, 2006 and 2005 were as follows:

	2006				2005
Millions of dollars	Amount		Weighted Average Interest Rate		Amount		Weighted Average Interest Rate
SCANA	$	—	—		$	25	4.43	%
SCE&G		238	5.38	%		196	4.40	%
Fuel Company		124	5.38	%		107	4.39	%
PSNC Energy		125	5.40	%		99	4.47	%

Total	$	487	5.38	%	$	427	4.42	%

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

Nuclear and fossil fuel inventories and emission allowances are financed through the issuance by Fuel Company of short-term commercial paper. All commercial paper borrowings are supported by five-year revolving credit facilities which expire on December 19, 2011. SCANA also has a five-year revolving credit facility which expires December 19, 2011.

6. COMMON EQUITY

SCANA Corporation's Restated Articles of Incorporation do not limit the dividends that may be paid on its common stock. However, the Restated Articles of Incorporation of SCE&G contain provisions that, under certain circumstances, which the Company considers to be remote, could limit the payment of cash dividends on its common stock.

With respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2006, approximately $54 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G's common stock.

Cash dividends on common stock were declared during 2006, 2005 and 2004 at an annual rate per share of $1.68, $1.56 and $1.46, respectively.

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

Millions of dollars	Unrealized Gains (Losses) on Securities			Cash Flow Hedging Activities			Minimum Pension Liability Adjustment			Deferred Costs of Employee Benefit Plans			Accumulated Other Comprehensive Income (Loss)
Balance, December 31, 2003	$	2		$	4		$	—		$	—		$	6
Other comprehensive loss		(2	)		(8	)		—			—			(10	)

Balance, December 31, 2004		—			(4	)		—			—			(4	)
Other comprehensive income (loss)		—			1			(1	)		—			—

Balance, December 31, 2005		—			(3	)		(1	)		—			(4	)
Other comprehensive income (loss)		—			(15	)		1			(11	)		(25	)

Balance, December 31, 2006	$	—		$	(18	)	$	—		$	(11	)	$	(29	)

During 2006 and 2005, no unrealized gains or losses on securities were reclassified into net income. The Company recognized a loss of $27.6 million, net of tax, and a gain of $4.0 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the years ended December 31, 2006 and 2005, respectively. As described in Notes 1 and 3, the Company adopted SFAS 158 at December 31, 2006 and recorded in accumulated other comprehensive income certain gains, losses, prior service costs and

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credits that have not yet been recognized through net periodic benefit cost, net of tax effects.

During 2004, $0.7 million was reclassified from unrealized gains and $12.5 million was reclassified from unrealized losses on securities into net income as a result of the sale of the Company's investments in ITC^DeltaCom, Inc. and the impairment and subsequent sale of the Company's investment in Knology, Inc. The Company also recognized a gain of $6.4 million, net of taxes, as a result of qualifying cash flow hedges whose hedged transactions occurred during the year ended December 31, 2004.

7. PREFERRED STOCK

Retirements under sinking fund requirements are at par values. The aggregate of the annual amounts of purchase or sinking fund requirements for preferred stock for the years 2007 through 2011 is $2.5 million. The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend. At December 31, 2006 SCE&G had shares of preferred stock authorized and available for issuance as follows:

Par Value	Authorized	Available for Issuance
$100	1,000,000	—
$ 50	592,405	300,000
$ 25	2,000,000	2,000,000

Preferred Stock (Not subject to purchase or sinking funds)

For each of the three years ended December 31, 2006, SCE&G had outstanding 1,000,000 shares of 6.52% $100 par and 125,209 shares of 5.00% $50 par Cumulative Preferred Stock (not subject to purchase or sinking funds).

Preferred Stock (Subject to purchase or sinking funds)

Changes in "Total Preferred Stock (Subject to purchase or sinking funds)" during 2006, 2005 and 2004 are summarized as follows:

	Series
	4.50%, 4.60% (A) & 5.125%			4.60% (B) & 6.00%			Total Shares		Millions of Dollars
Redemption Price	$	51.00		$	50.50
Balance at December 31, 2003		81,034			112,561		193,595		$	9.7
Shares Redeemed — $50 par value		(2,516	)		(6,600	)	(9,116	)		(0.5	)

Balance at December 31, 2004		78,518			105,961		184,479			9.2
Shares Redeemed — $50 par value		(1,475	)		(6,600	)	(8,075	)		(0.4	)

Balance at December 31, 2005		77,043			99,361		176,404			8.8
Shares Redeemed — $50 par value		(2,608	)		(6,600	)	(9,208	)		(0.5	)

Balance at December 31, 2006		74,435			92,761		167,196		$	8.3

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8. INCOME TAXES

Total income tax expense (benefit) attributable to income (before cumulative effect of accounting change) for 2006, 2005 and 2004 is as follows:

Millions of dollars			2006			2005			2004
Current taxes:
	Federal		$	93.9		$	10.2		$	(6.4	)
	State			9.8			11.1			(5.2	)

		Total current taxes		103.7			21.3			(11.6	)

Deferred taxes, net:
	Federal			11.7			1.7			84.5
	State			5.3			(6.9	)		5.4

		Total deferred taxes		17.0			(5.2	)		89.9

Investment tax credits:
	Deferred — state			5.0			5.1			10.0
	Amortization of amounts deferred — state			(3.3	)		(1.9	)		(2.1	)
	Amortization of amounts deferred — federal			(3.0	)		(3.1	)		(4.0	)

		Total investment tax credits		(1.3	)		0.1			3.9

Synthetic fuel tax credits — federal				—			(134.2	)		40.5

	Total income tax expense (benefit)		$	119.4		$	(118.0	)	$	122.7

The difference between actual income tax expense (benefit) and that amount calculated from the application of the statutory 35% federal income tax rate to pre-tax income (before cumulative effect of accounting change) is reconciled as follows:

Millions of dollars			2006			2005			2004
Income			$	304.0		$	319.5		$	257.1
Income tax expense (benefit)				119.4			(118.0	)		122.7
Preferred stock dividends				7.3			7.3			7.3

		Total pre-tax income	$	430.7		$	208.8		$	387.1

Income taxes on above at statutory federal income tax rate			$	150.7		$	73.1		$	135.5
Increases (decreases) attributed to:
	State income taxes (less federal income tax effect)			10.9			4.8			5.3
	Synthetic fuel tax credits			(33.5	)		(181.9	)		(2.9	)
	Allowance for equity funds used during construction			(0.2	)		(0.2	)		(5.5	)
	Deductible dividends — Stock Purchase Savings Plan			(6.5	)		(5.9	)		(5.5	)
	Amortization of federal investment tax credits			(3.0	)		(3.1	)		(4.0	)
	Non-taxable recovery of Lake Murray back-up dam project carrying costs			(2.3	)		(3.8	)		—
	Other differences, net			3.3			(1.0	)		(0.2	)

		Total income tax expense (benefit)	$	119.4		$	(118.0	)	$	122.7

The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $913.0 million at

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December 31, 2006 and $914.5 million at December 31, 2005 are as follows:

Millions of dollars			2006		2005
Deferred tax assets:
	Nondeductible reserves		$	103.8	$	84.8
	Unamortized investment tax credits			58.9		60.0
	Federal alternative minimum tax credit carryforward			22.1		44.0
	Deferred compensation			29.0		28.5
	Unbilled revenue			12.5		12.6
	Other			38.6		31.6

		Total deferred tax assets		264.9		261.5

Deferred tax liabilities:
	Property, plant and equipment			966.8		971.7
	Pension plan income			71.1		109.9
	Deferred employee benefit plan costs			56.1		—
	Deferred fuel costs			25.9		45.1
	Other			58.0		49.3

		Total deferred tax liabilities		1,177.9		1,176.0

Net deferred tax liability			$	913.0	$	914.5

The Internal Revenue Service has completed examinations of the Company's consolidated federal income tax returns through 2004, and the Company's tax returns through 2001 are closed for additional assessment. The IRS is currently examining S. C. Coaltech No. 1 LP., a synthetic fuel partnership in which the Company has an interest, for the 2004 tax year. The Company does not anticipate that any adjustments which might result from the examination will have a material impact on the earnings or the financial position of the Company. The Company continues to believe that all of its synthetic fuel tax credits have been properly claimed.

9. FINANCIAL INSTRUMENTS

Financial instruments for which the carrying amount does not equal estimated fair value at December 31, 2006 and 2005 were as follows:

	2006				2005
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,110.0	$	3,207.9	$	3,136.0	$	3,308.7
Preferred stock (subject to purchase or sinking funds)		8.3		7.8		8.8		8.2

The following methods and assumptions were used to estimate the fair value of financial instruments:

Fair values of long-term debt are based on quoted market prices of the instruments or similar instruments. For debt instruments for which no quoted market prices are available, fair values are based on net present value calculations. Carrying values reflect the fair values of interest rate swaps based on settlement values obtained from counterparties. Early settlement of long-term debt may not be possible or may not be considered prudent.

The fair value of preferred stock (subject to purchase or sinking funds) is estimated using market prices.

Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been considered.

Investments

SCANA and certain of its subsidiaries hold investments, some of which are marketable securities which are subject to SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," mark-to-market accounting and some of which are considered cost basis investments for which determination of fair value historically has been considered impracticable or which are otherwise non-marketable, such as

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life insurance policies. Equity holdings subject to SFAS 115 are categorized as "available for sale" and are carried at quoted market prices, with any unrealized gains and losses credited or charged to other comprehensive income (loss) within common equity on the Company's balance sheet. When indicated, and in accordance with its stated accounting policy, the Company performs periodic assessments of whether any decline in the value of these securities to amounts below the Company's cost basis is other than temporary. When other than temporary declines occur, write-downs are recorded through operations, and new (lower) cost bases are established. Insurance policies are carried at net cash surrender value. The Company also holds investments in several partnerships and joint ventures which are accounted for using the equity method.

Derivatives

SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" as amended, requires the Company to recognize all derivative instruments as either assets or liabilities in the statement of financial position and to measure those instruments at fair value. SFAS 133 further provides that changes in the fair value of derivative instruments are either recognized in earnings or reported as a component of other comprehensive income (loss), depending upon the intended use of the derivative and the resulting designation. The fair value of derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or quotations from independent parties.

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. The Risk Management Committee, which is comprised of certain officers, including the Company's Risk Management Officer and senior officers, apprises the Board of Directors with regard to the management of risk and brings to the Board's attention any areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

Commodities

The Company uses derivative instruments to hedge forward purchases of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy and financial institutions.

The Company's regulated gas operations (SCE&G and PSNC Energy) hedge gas purchasing activities using over-the-counter options and swaps and NYMEX futures and options. SCE&G's tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of these hedging activities are to be included in the PGA. As such, costs of related derivatives utilized to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. PSNC Energy's tariffs also include a provision for the recovery of actual gas costs incurred. PSNC Energy records premiums, transaction fees,

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margin requirements and any realized and unrealized 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.

The Company's nonregulated gas operations recognize gains and losses as a result of qualifying cash flow hedges whose hedged transactions occur during the reporting period and record them, net of taxes, in cost of gas. The Company recognized gains (losses) of approximately $(27.6) million, $4.0 million and $6.4 million during the years ended December 31, 2006, 2005 and 2004, respectively. Because these gains and losses resulted from hedging activities, their effects were necessarily offset by the recording of the related hedged transactions. The Company estimates that most of the December 31, 2006 unrealized loss balance of $(17.6) million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in 2007 as an increase to gas cost if market prices remain at current levels. As of December 31, 2006, all of the Company's cash flow hedges settle by their terms before the end of April 2009.

Interest Rates

The Company uses interest rate swap agreements to manage interest rate risk. These swaps provide for the Company to pay variable and receive fixed rate interest payments and are designated as fair value hedges of certain debt instruments. The Company may terminate a swap and may replace it with a new swap also designated as a fair value hedge. At December 31, 2006 the estimated fair value of the Company's swaps totaled $0.1 million related to combined notional amounts of $44.2 million.

Payments received upon termination of a swap are recorded as basis adjustments to long-term debt and are amortized as reductions to interest expense over the term of the underlying debt. The fair value of the swaps is recorded within other deferred debits or credits on the balance sheet. The resulting entries serve to reflect the hedged long-term debt at its fair value. Periodic receipts or payments related to the swaps are credited or charged to interest expense as incurred.

In anticipation of the issuance of debt, the Company may use interest rate lock or similar swap agreements to manage interest rate risk. These arrangements are designated as cash flow hedges. As such, payments received or made upon termination of such agreements are amortized to interest expense over the term of the underlying debt. As permitted by SFAS 104, "Statement of Cash Flows—Net Reporting of Certain Cash Receipts and Cash Payments and Classification of Cash Flows from Hedging Transactions,"payments received or made are classified as a financing activity in the consolidated statement of cash flows.

10. COMMITMENTS AND CONTINGENCIES

A. Nuclear Insurance

The Price-Anderson Indemnification Act deals with public liability for a nuclear incident and establishes the liability limit for third-party claims associated with any nuclear incident at $10.5 billion. Each reactor licensee is currently liable for up to $100.6 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $15 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, would be approximately $67.1 million per incident, but not more than $15 million per year.

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper, the one-third owner of Summer Station) with

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Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $14.1 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 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident at Summer Station. However, if such an incident were to occur, it would have a material adverse impact on the Company's results of operations, cash flows and financial position.

B. Environmental

SCE&G

In March 2005 the United States Environmental Protection Agency (EPA) issued a final rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. SCE&G has petitioned the United States Court of Appeals for the District of Columbia Circuit to review CAIR. Several other electric utilities have filed separate petitions. The petitioners seek a change in the method CAIR uses to allocate sulfur dioxide emission allowances to a method the petitioners believe is more equitable. The Company believes that installation of additional air quality controls will be needed to meet the CAIR requirements, although compliance plans and cost to comply with the rule have not been determined. Such costs will be material and are expected to be recoverable through rates.

SCE&G has been named, along with 53 others, by the EPA as a potentially responsible party (PRP) at the Alternate Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia. The EPA placed the site on the National Priorities List on April 19, 2006. AER conducted hazardous waste storage and treatment operations from 1975 to 2000, when the site was abandoned. While operational, AER processed fuels from waste oils, treated industrial coolants and oil/water emulsions, recycled solvents and blended hazardous waste fuels. During that time, SCE&G occasionally used AER for the processing of waste solvents, oily rags and oily wastewater. EPA and the State of Georgia have documented that a release or releases have occurred at the site leading to contamination of groundwater, surface water and soils. EPA and the State of Georgia have conducted a preliminary assessment and site inspection. The site has not been remediated nor has a clean-up cost been estimated. Although a basis for the allocation of clean-up

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costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recoveries, if any, is expected to be recoverable through rates.

SCE&G has been named, along with 29 others, by the EPA as a PRP at the Carolina Transformer Superfund site located in Fayetteville, North Carolina. The Carolina Transformer Company (CTC) conducted an electrical transformer rebuilding and repair operation at the site from 1967 to 1984. During that time, SCE&G occasionally used CTC for the repair of existing transformers, purchase of new transformers and sale of used transformers. In 1984, EPA initiated a clean-up of PCB-contaminated soil and groundwater at the site. EPA reports that it has spent $36 million to date. Although a basis for the allocation of clean-up costs among the PRPs is unclear, SCE&G does not believe that its involvement at this site would result in an allocation of costs that would have a material adverse impact on its results of operations, cash flows or financial condition. Any cost allocated to SCE&G arising from the remediation of this site, net of insurance recoveries, if any, is expected to be recoverable through rates.

SCE&G defers site assessment and cleanup costs and recovers them through rates (see Note 1). Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $17.9 million at December 31, 2006. The deferral includes the estimated costs associated with the following matters.

SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. SCE&G anticipates that remediation for contamination at the site will be completed in late 2007, with certain monitoring and retreatment activities continuing until 2011. As of December 31, 2006, SCE&G had spent $22.3 million to remediate the site and expects to spend an additional $1.1 million prior to entering a monitoring and reporting stage. In addition, the National Park Service of the Department of the Interior made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to this site. SCE&G expects to recover any cost arising from the remediation of this site through rates.

SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. One of the sites has been remediated and will undergo routine monitoring until released by the South Carolina Department of Health and Environmental Control (DHEC). The other sites are currently being investigated under work plans approved by DHEC. SCE&G anticipates that major remediation activities for the three sites will be completed by 2011. As of December 31, 2006, SCE&G has spent $4.8 million related to these three sites, and expects to spend an additional $11.2 million. SCE&G expects to recover any cost arising from the remediation of these sites through rates.

PSNC Energy

PSNC Energy is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy's actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. PSNC Energy has recorded a liability and associated regulatory asset of $6.9 million, which reflects its estimated remaining liability at December 31, 2006. PSNC Energy expects to recover any cost allocable to PSNC Energy

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arising from the remediation of these sites through rates.

C. Franchise Agreements

See Note 1B for a discussion of the electric and gas franchise agreements between SCE&G and the cities of Columbia and Charleston.

D. Claims and Litigation

In 1999, an unsuccessful bidder for the purchase of certain propane gas assets of the Company filed suit against SCANA in Circuit Court, seeking unspecified damages. The suit alleged the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. On October 21, 2004, the jury issued an adverse verdict on this matter against SCANA for four causes of action for damages totaling $48 million. In accordance with generally accepted accounting principles, in the third quarter of 2004 SCANA accrued a liability of $18 million, which was its reasonable estimate of the minimum liability that was probable if the final judgment were to be consistent with the jury verdict. While the judgment was being appealed, in May 2006 SCANA paid the plaintiff $11 million in settlement of its claims.

A claim against SCANA for $2.7 million for reimbursement of legal fees and expenses under an indemnification and hold harmless agreement in the contract for the sale of the propane gas assets was settled in November 2006. A provision for this loss had been previously recorded.

In August 2003, SCE&G was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and SCE&G in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. Since that time, the plaintiffs have dismissed defendants Duke Energy and Progress Energy and are proceeding against SCE&G only. The plaintiffs are seeking damages for the alleged improper use of electric transmission and distribution easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to nonutility third parties or telecommunication companies for other than the electric utility's internal use along the electric transmission and distribution line rights-of-way constitutes a trespass. It is anticipated that this case may not go to trial before 2008. SCANA and SCE&G are confident of the propriety of SCE&G's actions and intend to mount a vigorous defense. SCANA and SCE&G further believe that the resolution of these claims will not have a material adverse impact on their results of operations, cash flows or financial condition.

In May 2004, SCANA and SCE&G were served with a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation. The case was filed in South Carolina's Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges that SCANA and SCE&G made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication equipment to transmit communications other than SCANA's and SCE&G's electricity-related internal communications. The plaintiff asserted causes of action for unjust enrichment, trespass, injunction and declaratory judgment. The plaintiff did not assert a specific dollar amount for the claims. SCANA & SCE&G believe their actions are consistent with governing law and the applicable documents granting easements and rights-of-way. The Circuit Court granted SCANA's and SCE&G's motion to dismiss and issued an order dismissing the case in

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June 2005. The plaintiff appealed to the South Carolina Supreme Court. The Supreme Court overruled the Circuit Court in October 2006 and returned the case to the Circuit Court for further consideration. It is anticipated that this case may not go to trial before 2008. SCANA and SCE&G will continue to mount a vigorous defense and believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.

A complaint was filed in October 2003 against SCE&G by the State of South Carolina alleging that SCE&G violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality's limits. The complaint alleged that SCE&G failed to obey, observe or comply with the lawful order of the SCPSC by charging franchise fees to those not residing within a municipality. The complaint sought restitution to all affected customers and penalties of up to $5,000 for each separate violation. The claim against SCE&G has been settled by an agreement between the parties, and the settlement has been approved by South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. In addition, SCE&G filed a petition with the SCPSC in October 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to SCE&G's electric and gas service, to approve SCE&G's efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation that the SCPSC deems just and proper to regulate the franchise fee collection process. A hearing on this petition has not been scheduled. The Company believes that the resolution of these matters will not have a material adverse impact on its results of operations, cash flows or financial condition.

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

E. Settlement Related to Power Marketing Practices

On January 18, 2007 FERC approved a settlement with SCE&G regarding the use of SCE&G's electric transmission system by its power marketing division. SCE&G identified, investigated and self-reported instances of improper utilization of network transmission services, rather than point-to-point transmission services, for purchases and sales of electricity in violation of SCE&G's open access transmission tariff and applicable FERC orders under the Federal Power Act that prohibit the use of network transmission service in support of certain "off-system" sales.

As part of the settlement, SCE&G agreed that it would not retain any benefit derived from the transactions and paid a $9 million penalty to the United States Treasury. Additionally, SCE&G agreed to credit an additional $1.4 million to benefit retail native load ratepayers and SCE&G's non-affiliated firm transmission customers. The credit to the retail native load ratepayers was applied toward the fuel clause mechanism in January 2007. The credit to the non-affiliated firm transmission customers was refunded directly to those customers. An additional $0.4 million was credited to transmission revenue to the benefit of SCE&G's rate payers. The effects of the settlement were accrued in 2006.

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F. Operating Lease Commitments

The Company is obligated under various operating leases with respect to office space, furniture and equipment. Leases expire at various dates through 2013. Rent expense totaled approximately $15.0 million, $13.9 million and $11.8 million in 2006, 2005 and 2004, respectively. Future minimum rental payments under such leases are as follows:

	Millions of dollars
2007	$	30
2008		14
2009		10
2010		1
2011		—
Thereafter		2

Total	$	57

At December 31, 2006 minimum rentals to be received under noncancelable subleases with remaining lease terms in excess of one year totaled approximately $5.7 million.

G. Purchase Commitments

The Company is obligated for purchase commitments that expire at various dates through 2034. Amounts expended under forward contracts for natural gas purchases, gas transportation capacity agreements, coal supply contracts, nuclear fuel contracts, construction projects and other commitments totaled $2.4 billion, $2.2 billion and $1.6 billion in 2006, 2005 and 2004, respectively. Future payments under such purchase commitments are as follows:

	Millions of dollars
2007	$	1,623
2008		811
2009		1,221
2010		548
2011		499
Thereafter		3,459

Total	$	8,161

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

In addition, included in purchase commitments 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 commitments without penalty.

H. Asset Retirement Obligations

In accordance with SFAS 143, "Accounting for Asset Retirement Obligations," as interpreted by FIN 47, "Accounting for Conditional Asset Retirement Obligations," the Company recognizes a liability for the fair value of an ARO when incurred if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.

SFAS 143 applies to the legal obligation associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation and relates primarily to the Company's regulated utility operations. As of December 31, 2006, the Company has recorded an ARO of approximately $92 million for nuclear plant decommissioning (see Note 1G) and an ARO of approximately $199 million for other conditional obligations 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.

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

Millions of dollars	2006			2005
Beginning balance	$	322		$	124
Liabilities incurred		1			—
Liabilities settled		(2	)		—
Accretion expense		17			7
Revisions in estimated cash flows		(46	)		—
Adoption of FIN 47		—			191

Ending Balance	$	292		$	322

Revisions in estimated cash flows are primarily attributable to the estimated ARO associated with decommissioning Summer Station. The reduction is principally related to the expectation of lower decommissioning cost escalations than had been assumed in the prior cash flow analysis.

11. SEGMENT OF BUSINESS INFORMATION

The Company's reportable segments are described below. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. 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.

Gas Transmission is comprised of CGTC which, effective November 1, 2006, began operating as an open access, transportation-only pipeline company regulated by FERC. CGTC resulted from the merger of SCG Pipeline (previously reported in All Other) into SCPC. Prior to the merger, SCPC purchased, transported and sold natural gas intrastate and SCG Pipeline transported gas interstate. The results for CGTC, SCPC and SCG Pipeline appear in the Gas Transmission reportable segment for all periods presented.

Retail Gas Marketing markets natural gas in Georgia and is regulated as a marketer by the Georgia Public Service Commission. Energy Marketing markets electricity and natural gas to industrial, large commercial and wholesale customers, primarily in the Southeast.

The Company's 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 gas segments differ from each other in their regulatory environment, the class of customers each serves and the marketing strategies resulting from those differences. The marketing segments differ from each other in their respective markets and customer type.

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Disclosure of Reportable Segments (Millions of dollars)

2006	Electric Operations			Gas Distribution		Gas Transmission		Retail Gas Marketing		Energy Marketing			All Other			Adjustments/ Eliminations			Consolidated Total
Customer Revenue	$	1,877		$	1,078	$	179	$	608	$	821		$	66		$	(66	)	$	4,563
Intersegment Revenue		9			—		322		—		128			306			(765	)		—
Operating Income		456			83		30		n/a		n/a			n/a			34			603
Interest Expense		15			24		7		2		—			—			161			209
Depreciation and Amortization		268			54		8		3		—			15			(15	)		333
Income Tax Expense		3			16		11		19		—			6			64			119
Net Income (Loss)		n/a			n/a		n/a		30		—			(11	)		291			310
Segment Assets		5,520			1,847		315		208		142			649			1,136			9,817
Expenditures for Assets		304			174		13		—		3			35			(2	)		527
Deferred Tax Assets		n/a			n/a		7		3		12			2			10			34
2005
Customer Revenue	$	1,909		$	1,168	$	237	$	664	$	799		$	70		$	(70	)	$	4,777
Intersegment Revenue		4			1		427		—		146			317			(895	)		—
Operating Income		299			75		26		n/a		n/a			n/a			36			436
Interest Expense		13			21		7		2		—			—			169			212
Depreciation and Amortization		450			49		8		3		—			13			(13	)		510
Income Tax Expense (Benefit)		4			18		8		14		(1	)		12			(173	)		(118	)
Net Income (Loss)		n/a			n/a		n/a		24		(1	)		(69	)		366			320
Segment Assets		5,531			1,701		427		284		128			553			895			9,519
Expenditures for Assets		280			122		5		—		1			18			(41	)		385
Deferred Tax Assets		n/a			n/a		6		8		3			2			7			26
2004
Customer Revenue	$	1,688		$	914	$	212	$	552	$	520		$	58		$	(59	)	$	3,885
Intersegment Revenue		4			—		346		—		77			297			(724	)		—
Operating Income		550			67		23		n/a		n/a			n/a			(44	)		596
Interest Expense		10			21		5		3		—			—			163			202
Depreciation and Amortization		208			47		8		2		—			11			(11	)		265
Income Tax Expense (Benefit)		(2	)		15		6		18		(1	)		(9	)		96			123
Net Income (Loss)		n/a			n/a		n/a		29		(2	)		(42	)		272			257
Segment Assets		5,365			1,540		393		201		91			470			946			9,006
Expenditures for Assets		389			86		11		—		3			18			(6	)		501
Deferred Tax Assets		n/a			n/a		5		4		3			2			(4	)		10

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Revenues and assets from segments below the quantitative thresholds are attributable to ten other direct and indirect wholly-owned subsidiaries of the Company. These 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.

Management uses operating income to measure segment profitability for SCE&G and other regulated operations and evaluates utility plant, net, for segments attributable to SCE&G. As a result, SCE&G does not allocate interest charges, income tax expense (benefit) or assets other than utility plant to its segments. For nonregulated operations, management uses net income (loss) as the measure of segment profitability and evaluates total assets for financial position. Interest income is not reported by segment and is not material. In accordance with SFAS 109, 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 reportable segments. Revenues from non-reportable segments are included in Other Income. Therefore the adjustments to total operating revenues remove revenues from non-reportable segments. Adjustments to Net Income consist of SCE&G's unallocated net income.

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 (Benefit), Expenditures for Assets and Deferred Tax Assets include primarily the totals from SCANA or SCE&G that are not allocated to the segments. Interest Expense is also adjusted to eliminate charges between affiliates. Adjustments to Depreciation and Amortization consist of non-reportable segment expenses, which are not included in the depreciation and amortization reported on a consolidated basis. Expenditures for Assets are adjusted for AFC. Deferred Tax Assets are adjusted to net them against deferred tax liabilities on a consolidated basis.

12. QUARTERLY FINANCIAL DATA (UNAUDITED)

2006 Millions of dollars, except per share amounts	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Annual
Total operating revenues	$	1,389	$	944	$	1,062	$	1,168	$	4,563
Operating income		185		122		156		140		603
Income before cumulative effect of accounting change		92		58		89		65		304
Cumulative effect of accounting change, net of taxes⁽¹⁾		6		—		—		—		6
Net income		98		58		89		65		310
Basic and diluted earnings per share		.85		.50		.76		.57		2.68
2005 Millions of dollars, except per share amounts
Total operating revenues	$	1,266	$	891	$	1,127	$	1,493	$	4,777
Operating income		28		85		179		144		436
Net income		101		44		100		75		320
Basic and diluted earnings per share		.89		.39		.88		.65		2.81

⁽¹⁾: The cumulative effect of accounting change is attributable to the adoption of SFAS 123(R) in the first quarter of 2006. See Note 3.

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MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of SCANA Corporation (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 Chief Executive Officer (CEO) and Chief Financial Officer (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, 2006. 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. Based on this assessment, SCANA's management believes that, as of December 31, 2006, internal control over financial reporting is effective based on those criteria.

SCANA's independent registered public accounting firm has issued an attestation report on the assessment of SCANA's internal control over financial reporting. This report follows.

February 28, 2007

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ATTESTATION REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON MANAGEMENT'S ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING

SCANA Corporation

We have audited management's assessment, included in the accompanying Management Report On Internal Control Over Financial Reporting, that SCANA Corporation and subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework 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. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of 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, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

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, management's assessment that SCANA Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control — Integrated Framework

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issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, SCANA Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework 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, 2006, of SCANA Corporation and subsidiaries and our report dated February 28, 2007, expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Company's adoption of Statement of Financial Accounting Standards No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans."

Columbia, South Carolina
February 28, 2007

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MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

COMMON STOCK INFORMATION

Price Range (New York Stock Exchange Composite Listing):

	2006								2005
	4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.		4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.
High	$	42.43	$	41.65	$	40.41	$	41.42	$	43.37	$	43.65	$	43.30	$	40.04
Low	$	39.55	$	38.35	$	36.92	$	39.02	$	37.79	$	39.90	$	36.56	$	36.70

DIVIDENDS PER SHARE

SCANA declared quarterly dividends on its common stock of $.42 per share in 2006 and $.39 per share in 2005.

SCANA common stock trades on The New York Stock Exchange, using the ticker symbol SCG. Newspaper stock listings use the name SCANA. At February 20, 2007 there were 116,664,933 shares of SCANA common stock outstanding which were held by 34,326 stockholders of record.

On February 20, 2007, the closing price of SCANA common stock on the New York Stock Exchange was $42.23.

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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
William B. Timmerman	60	Chairman of the Board, President and Chief Executive Officer	*-present
Jimmy E. Addison	46	Senior Vice President and Chief Financial Officer Vice President — Finance	2006-present *-2006
Joseph C. Bouknight	54	Senior Vice President — Human Resources Vice President Human Resources — Dan River, Inc. — Danville, VA	2004-present *-2004
George J. Bullwinkel	58	President and Chief Operating Officer — SEMI President and Chief Operating Officer — SCI and ServiceCare President and Chief Operating Officer — SCPC and SCG Pipeline	2004-present -present -2004
Sarena D. Burch	49	Senior Vice President — Fuel Procurement and Asset Management — SCE&G and PSNC Energy Senior Vice President — Fuel Procurement and Asset Management — SCPC Deputy General Counsel and Assistant Secretary	2003-present 2003-2006 *-2003
Stephen A. Byrne	47	Senior Vice President — Generation, Nuclear and Fossil Hydro — SCE&G Senior Vice President — Nuclear Operations	2004-present *-2004
P. V. Fant	53	Senior Vice President — Transmission Services President and Chief Operating Officer — CGTC (formerly SCPC and SCG) Executive Vice President — SCPC and SCG Pipeline	2004-present 2004-present *-2004
Kevin B. Marsh	51	President and Chief Operating Officer — SCE&G Senior Vice President and Chief Financial Officer President and Chief Operating Officer — PSNC Energy	2006-present -2006 -2003
Charles B. McFadden	62	Senior Vice President — Governmental Affairs and Economic Development — SCANA Services Vice President — Governmental Affairs and Economic Development — SCANA Services	2003-present *-2003
Francis P. Mood, Jr.	69	Senior Vice President, General Counsel and Assistant Secretary Attorney, Haynsworth Sinkler Boyd, P.A. — Columbia, SC	2005-present *-2005

*: Indicates position held at least since March 1, 2002.

CERTIFICATIONS

Following the 2006 Annual Meeting, SCANA submitted to the New York Stock Exchange (NYSE) the certification of the Chief Executive Officer required by Section 303A.12(a) of the NYSE Listed Company Manual. On March 1, 2007 SCANA filed with the Securities and Exchange Commission its Form 10-K which included, as Exhibits 31.1 and 31.2, the required Chief Executive Officer and Chief Financial Officer Sarbanes Oxley Section 302 Certifications.

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SCANA Corporation
1426 Main Street
Columbia, SC 29201
www.scana.com

Printed on Recycled Paper

ADMISSION TICKET
SCANA CORPORATION Annual Meeting of Shareholders April 26, 2007
8:00 A.M.— Refreshments
9:00 A.M.— Meeting Begins
Holliday Alumni Center
The Citadel
69 Hagood Avenue
Charleston, SC 29403


PLEASE MARK VOTE /x/
Voting Instructions for Proposals 1 and 2
To vote for all nominees, mark the "For All" box. To withhold voting for all nominees, mark the "Withhold" box. To withhold voting for a particular nominee, mark the "For All Except" 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 OF DIRECTORS RECOMMENDS A VOTE "FOR" THE ELECTION OF ALL NOMINEES AS DIRECTORS AND "FOR" PROPOSAL 2.
1. Election of Class II Nominees — Terms Expire 2010	01- 02- 03-	W. Hayne Hipp Harold C. Stowe G. Smedes York
2. Approval of Appointment of Independent Registered Public Accounting Firm



ACCT #:
To vote, mark an 'X' in the appropriate box.
1.		For ALL Nominees / / Withhold Authority / / For ALL EXCEPT the following: / / (Write number(s) of nominee(s) below)

For / / Against / / Abstain / /

Dated			, 2007

Sign here X
exactly as name(s) appears on this card.
X

SHARES WILL BE VOTED IN ACCORDANCE WITH YOUR
INSTRUCTIONS AS SET FORTH ABOVE.
IF NO INSTRUCTIONS ARE GIVEN, THE SHARES
REPRESENTED BY THIS PROXY WILL BE VOTED "FOR"
THE ELECTION OF ALL NOMINEES AS DIRECTORS AND
"FOR" PROPOSAL 2.
I will attend the Annual Meeting of
Shareholders on April 26, 2007 ........ / /

SCANA CORPORATION
Annual Meeting of Shareholders
April 26, 2007

FORM OF PROXY
SCANA CORPORATION

Proxy Solicited on Behalf of
Board of Directors

The undersigned hereby appoints W.B. Timmerman and J.E. Addison, or either of them, as proxies with full power of substitution, to vote all shares of common stock standing in the undersigned's name on the books of the Company, at the Annual Meeting of Shareholders on April 26, 2007, and at any adjournment thereof, as instructed on the reverse hereof and in their discretion upon all other matters which may properly be presented for consideration at said meeting.

Please vote your proxy today, using one of the three convenient voting methods.

INSTRUCTIONS FOR VOTING YOUR PROXY

SCANA offers shareholders three alternative methods of voting this proxy:

• By Telephone (using a touch-tone telephone) • Through the Internet (using a browser)
• By Mail (using the attached proxy card and postage-paid envelope)

Your telephone or Internet vote authorizes the named proxies to vote your shares in the same manner as if you had returned your proxy card. We encourage you to use these cost-effective and convenient methods of voting, 24 hours a day, 7 days a week.

TELEPHONE VOTING Available until 5:00 p.m. Eastern Daylight Time on April 25, 2007

•  This method of voting is available for residents of the U.S. and Canada
•  On a touch-tone telephone, call TOLL FREE 1-877-412-6959, 24 hours a day, 7 days a week
•  In order to vote via telephone, have the voting form in hand, call the number above and follow the instructions
•  Your vote will be confirmed and cast as you directed

INTERNET VOTING Available until 5:00 p.m. Eastern Daylight Time on April 25, 2007

•  Visit the Internet voting website at www.proxy.georgeson.com
•  In order to vote online, have the voting form in hand, go to the website listed above and follow the instructions
•  Your vote will be confirmed and cast as you directed
•  You will incur only your usual Internet charges

VOTING BY MAIL

• Mark, sign and date your proxy card and return it in the enclosed postage-paid envelope
• If you are voting by telephone or through the Internet, please do not return your proxy card


From Interstate 26 Eastbound:
• Take the Rutledge Avenue exit (219-A).
• Follow Rutledge Avenue approximately 1.2 miles, turn right onto Congress Street.
• Follow Congress Street until the intersection of Hagood Ave, turn left on Hagood and the Alumni Center will be on your right (69 Hagood Ave.)
From US 17 Southbound:
• After crossing the Ravenel Bridge, continue along U.S. 17 South, then turn right onto Hagood Avenue at McDonald's, just before crossing the Ashley River.
• Follow Hagood Avenue to the football stadium, which will be on your right. The Alumni Center will be on your left (69 Hagood Ave.).
From US 17 Northbound:
• Immediately after passing the round Holiday Inn and crossing the Ashley River Bridge, exit US 17 toward the right, but stay in the exit ramp's left-hand lane until you reach the traffic light.
• Turn left onto Lockwood Drive, continue .5 miles, just before the baseball park the street will make a sharp right turn and the name will change to Fishburne Street.
• Go .3 miles, then turn left at the stop light onto Hagood Avenue.
• Follow Hagood Avenue to the football stadium, which will be on your right. The Alumni Center will be on your left (69 Hagood Ave.).
As you face the Alumni Center, parking will be to the right of the building. Do not park in front or to the left of the building.

Proxy Notification

Dear Shareholder,

You have elected to receive your 2007 Proxy Statement and 2006 Performance Report electronically.

SCANA Corporation has made available on-line its 2007 annual meeting proxy materials. Please access www.proxy.georgeson.com to review the proxy materials and vote your shares for our upcoming annual meeting. Once there, please direct your attention to the top right of the page where you will find buttons designated for each specific document. In order to cast your vote, please follow the instructions on the back of the proxy card. Your vote is very important to us. Please remember to cast your vote before exiting the website.

Sincerely,
Shareholder Services
SCANA Corporation

QuickLinks

SCANA Corporation 1426 Main Street Columbia, South Carolina 29201 PROXY STATEMENT
FIVE PERCENT BENEFICIAL OWNERSHIP OF SCANA COMMON STOCK
SUMMARY COMPENSATION TABLE
2006 GRANTS OF PLAN-BASED AWARDS
OUTSTANDING EQUITY AWARDS AT 2006 FISCAL YEAR-END
2006 OPTION EXERCISES AND STOCK VESTED
PENSION BENEFITS
2006 NONQUALIFIED DEFERRED COMPENSATION
2006 DIRECTOR COMPENSATION
SCANA Corporation Comparison of Five-Year Cumulative Total Return* SCANA Corporation, Long-Term Equity Compensation Plan Peer Groups, S&P Utilities and S&P 500
Proxy Notification