DEF 14A 1 a2168382zdef14a.htm DEF 14A
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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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o		Soliciting Material Pursuant to §240.14a-12

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 2006 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 17, 2006

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 27, 2006. The meeting will be held at Leaside, 100 East Exchange Place, Columbia, South Carolina 29209. An admission ticket is enclosed. Directions to Leaside are on the back of the ticket.

Enclosed is SCANA's Proxy Statement for the 2006 Annual Meeting. The approximate date of mailing for this proxy statement and enclosures is March 17, 2006. 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 rather than in the enclosed 2005 Annual Report.

•: A Notice of 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 2005 business results.
•: If you vote by mail and plan to attend the meeting, please so indicate on the enclosed proxy card. If you vote by telephone or through the Internet, 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 20, 2006.
•: Refreshments will be served beginning at 8:00 A.M. at Leaside.

Your vote is important. We encourage you to read this proxy statement and vote your shares as soon as possible. The enclosed proxy card gives detailed instructions on telephone and Internet voting. Please vote your proxy card today 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.

You have an opportunity to elect to view future proxy statements and annual report materials through the Internet, instead of receiving paper copies in the mail. Electing this option will help us reduce printing and postage costs and is more environmentally friendly. Additional information can be found on page 3.

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	7
	BOARD MEETINGS — COMMITTEES OF THE BOARD	9
	GOVERNANCE INFORMATION	11
	DIRECTOR COMPENSATION	14
	COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION	15
	RELATED TRANSACTIONS	15
	SHARE OWNERSHIP OF DIRECTORS, NOMINEES AND EXECUTIVE OFFICERS	16
	FIVE PERCENT OWNERSHIP OF SCANA COMMON STOCK	17
	EXECUTIVE COMPENSATION	18
	REPORT ON EXECUTIVE COMPENSATION	23
	PERFORMANCE GRAPH	27
	AUDIT COMMITTEE REPORT	29
	PROPOSAL 2 — APPROVAL OF APPOINTMENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	30
	OTHER INFORMATION	31
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 27, 2006
Meeting Time:	9:00 A.M., Eastern Daylight Time
Meeting Place:	Leaside 100 East Exchange Place Columbia, South Carolina 29209
Meeting Record Date:	March 10, 2006
Meeting Agenda:	1)	Election of four Class I Directors and one Class III Director
	2)	Approval of Appointment of Independent Registered Public Accounting Firm

Shareholder List

A list of shareholders entitled to vote at the meeting will be available for inspection, upon written request by a shareholder, at SCANA's Corporate Offices, 1426 Main Street, Columbia, South Carolina 29201, during business hours from March 17, 2006 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. See page 31.

By Order of the Board of Directors,

Lynn M. Williams
Corporate Secretary

THE ENCLOSED PROXY CARD GIVES DETAILED INSTRUCTIONS ON TELEPHONE AND INTERNET VOTING. PLEASE VOTE YOUR PROXY CARD TODAY ELECTRONICALLY BY TELEPHONE OR THROUGH THE INTERNET, OR BY SIGNING, DATING AND MAILING YOUR PROXY CARD IN THE ENVELOPE ENCLOSED.

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 2006 Annual Meeting of Shareholders, which will be held at 9:00 A.M., Eastern Daylight Time on Thursday, April 27, 2006, and at any adjournment or postponement of the meeting. The meeting will be held at Leaside, 100 East Exchange Place, Columbia, South Carolina 29209. These proxy materials are first being mailed to shareholders of record on or about March 17, 2006.

VOTING PROCEDURES

Your Vote Is Important

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

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, and return it to SCANA in the enclosed postage-paid envelope. If you want to view future proxy statements and annual report materials through the Internet, check the box provided on the proxy card. 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 nominees for directors 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 10, 2006, there were 115,146,894 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 elect to view all future proxy statements and annual report information through the Internet instead of receiving the material by mail. If you choose to access future proxy statements and annual report information online, you will be notified of the website access address and other necessary information to view the materials and to cast your vote. If you choose to view your proxy materials through the Internet, you may incur costs, such as telephone and Internet access charges, for which you will be responsible.

If you wish to take advantage of this option, you may make this election when voting your proxy. If you vote by telephone or through the Internet, simply respond to the question when prompted. If you vote by mail, mark the applicable box on your proxy card.

If you elect to view the proxy statement and annual report material through the Internet and then change your mind, you may revoke your election at any time by calling Shareholder Services at 1-800-763-5891.

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 I Directors will expire at the Annual Meeting. The Board has decided to nominate the existing Class I Directors, Messrs. Bennett, Burkhardt, Sloan and Ms. Miller for reelection at the Annual Meeting. The terms of the Class I Directors elected at the Annual Meeting, except Mr. Burkhardt, will expire in 2009. Mr. Burkhardt's term will expire in 2007 when he reaches mandatory retirement age.

On December 20, 2005, the Board elected Sharon Allred Decker to fill the seat vacated upon the death of William B. Bookhart, Jr. in November 2005. Mrs. Decker was recommended to the Board by the Chief Executive Officer of SCANA and was elected to serve until the 2006 Annual Meeting. The Board has now nominated Mrs. Decker for election by the shareholders as a Class III Director with a term expiring at the 2008 Annual Meeting.

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 nominees for directors.

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. Share ownership is shown as of March 10, 2006. Hypothetical shares are those held as of March 10, 2006 under the Director Compensation and Deferral Plan for all directors except Mr. Timmerman, who does not participate in that plan. Mr. Timmerman's hypothetical shares are those held by him as of March 10, 2006 under the Executive Deferred Compensation Plan. Each of the directors is also a director of South Carolina Electric & Gas Company and Public Service Company of North Carolina, Incorporated, subsidiaries of SCANA.

NOMINEES FOR DIRECTORS

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

		James A. Bennett (Age 45) Director since 1997		Shares: 2,603 Hypothetical Shares: 13,171
		Mr. Bennett has been Executive Vice President and Director of Public Affairs, First Citizens Bank, Columbia, South Carolina since August 2002. Previously, he was President and Chief Executive Officer of South Carolina Community Bank, Columbia, South Carolina from May 2000 to July 2002.
		William C. Burkhardt (Age 68)* Director since 2000		Shares: 13,121 Hypothetical Shares: 16,074
		Mr. Burkhardt has served as Chairman and Chief Executive Officer of Titan Holdings, LLC, a real estate investment company, Raleigh, North Carolina since May 2004. He was Chief Executive Officer of Capital Bank, Raleigh, North Carolina from October 2003 until retiring in May 2004. From May 2000 until October 2003, Mr. Burkhardt pursued personal interests. Mr. Burkhardt retired as President and Chief Executive Officer of Austin Quality Foods, Inc., a production and distribution company of baked snacks for the food industry, Cary, North Carolina in May 2000, having served in that position since 1980. Mr. Burkhardt is a director of Capital Bank, Raleigh, North Carolina and Plaza Belmont II, Kansas City, Missouri.
		Lynne M. Miller (Age 54) Director since 1997		Shares: 3,666 Hypothetical Shares: 15,357
		Ms. Miller has been Senior Business Consultant to Quanta Capital Holdings, Inc., a specialty insurer, since August 2005. 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., Washington, D.C.

* Although terms of the Class I directors expire in 2009, Mr. Burkhardt will reach age 70 in 2007. SCANA's Articles of Incorporation mandate that the term of any director who is not a salaried employee expire at the annual meeting next preceding the date such director attains age 70. Accordingly, Mr. Burkhardt's term will expire at the 2007 Annual Meeting.

		Maceo K. Sloan (Age 56) Director since 1997		Shares: 1,831 Hypothetical Shares: 14,490
		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, 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 and a director of M&F Bancorp, Inc. and its subsidiary, Mechanics and Farmers Bank, Durham, North Carolina.

Nominee for Class III Director—Term to Expire at the Annual Meeting in 2008

		Sharon A. Decker (Age 49) Director since 2005		Shares: 1,112 Hypothetical Shares: 0
		Mrs. Decker is the founder and has been the principal of The Tapestry Group LLC, a motivational speaking company, Rutherfordton, North Carolina since September 2004. Mrs. Decker previously served as President of Tanner Holdings 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.

CONTINUING DIRECTORS

Class II Directors—Terms to Expire at the Annual Meeting in 2007

		W. Hayne Hipp (Age 66) Director since 1983		Shares: 14,058 Hypothetical Shares: 11,527
		Mr. Hipp is a private investor. Prior to its acquisition in January 2006, Mr. Hipp was Chairman, Chief Executive Officer and a director of The Liberty Corporation, a broadcasting holding company headquartered in Greenville, South Carolina. He held these positions for more than five years.
		Harold C. Stowe (Age 59) Director since 1999		Shares: 2,732 Hypothetical Shares: 11,538
		Mr. Stowe retired in February 2005 as President of Canal Holdings, LLC, a forest products industry company, Conway, South Carolina. Mr. Stowe had served as President of Canal Holdings, LLC, and its predecessor company since March 1997. Mr. Stowe is a director of Ruddick Corporation, Charlotte, North Carolina.
		G. Smedes York (Age 65) Director since 2000		Shares: 13,204 Hypothetical Shares: 14,750
		Mr. York has been President and Treasurer of York Properties, Inc., a full-service commercial and residential real estate company, Raleigh, North Carolina since 1970. Mr. York also is Chairman of the Board of York Simpson Underwood, a residential brokerage company, and of McDonald-York, Inc., a general contractor, both in Raleigh, North Carolina.

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

		Bill L. Amick (Age 62) Director since 1990		Shares: 11,016 Hypothetical Shares: 13,091
		Mr. Amick is Chairman of the Board of Amick Farms, Inc., Amick Processing, Inc. and Amick Broilers, Inc., a vertically integrated broiler operation, Batesburg, South Carolina. He has held these positions for more than five years. Mr. Amick is a director of Blue Cross and Blue Shield of South Carolina.
		D. Maybank Hagood (Age 44) Director since 1999		Shares: 1,540 Hypothetical Shares: 4,089
		Mr. Hagood has been President and Chief Executive Officer of Southern Diversified Distributors, LLC, a provider of logistic and distribution services, Charleston, South Carolina since 2003. Mr. Hagood also has been President and Chief Executive Officer of William M. Bird and Company, Inc., a subsidiary of Southern Diversified Distributors, LLC, a wholesale distributor of floor covering materials, Charleston, South Carolina since 1993.
		William B. Timmerman (Age 59) Director since 1991		Shares: 181,865* Hypothetical Shares: 37,768
		Mr. Timmerman has been Chairman of the Board and Chief Executive Officer of SCANA since March 1, 1997. He has been President of SCANA since December 13, 1995.

* Includes 123,067 shares subject to currently exercisable options.

There are no family relationships among any of SCANA's directors, director nominees and executive officers.

BOARD MEETINGS—COMMITTEES OF THE BOARD

The Board held four meetings in 2005. Each director attended at least 75% of all Board and applicable committee meetings during 2005. Directors are expected to attend the annual shareholders meeting absent extenuating circumstances. All of the directors, except one, attended the 2005 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 and Governance Committee, the Audit Committee and the Nuclear Oversight Committee. The charters of the Human Resources Committee, the Nominating and Governance Committee, the Audit Committee and the Nuclear Oversight Committee can be found on SCANA's website at www.scana.com under the caption, "Investor Information—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 2005


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 Meetings

HUMAN RESOURCES	•	reviews and makes recommendations to the Board with respect to	2 Meetings
COMMITTEE		compensation plans
	•	recommends to the Board persons to serve as senior officers of
W. C. Burkhardt, Chairman		SCANA and its subsidiaries
B. L. Amick	•	recommends to the Board salary and compensation levels, including
J. A. Bennett		fringe benefits, for officers of SCANA and its subsidiaries
D. M. Hagood	•	approves goals and objectives with respect to the compensation of
M. K. Sloan		the Chief Executive Officer, evaluates the Chief Executive Officer's
		performance and sets his compensation based on this evaluation
	•	reviews management's resources and development, and
		recommends to the Board succession plans for senior management
	•	reviews the investment policies of SCANA's Retirement Plan
	•	provides direction regarding the operation of SCANA's Retirement
		Plan and other employee benefit plans
	•	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
	•	evaluates annually its own performance and the adequacy of its charter


NOMINATING AND	•	recommends the slate of director nominees to be presented for	3 Meetings
GOVERNANCE		election at each annual meeting and director nominees to fill vacancies
COMMITTEE	•	reviews and evaluates shareholder nominees for director in accordance
		with the nominating criteria
B. L. Amick, Chairman	•	evaluates the qualifications and performance of incumbent directors
D. M. Hagood	•	recommends assignments of directors to serve on Board
W. H. Hipp		committees
H. C. Stowe	•	reviews annually, and revises as necessary, SCANA's Governance
G. S. York		Principles
	•	evaluates annually the Board's effectiveness
	•	evaluates periodically the size, composition and organizational
		and operational structure of the Board and recommends to the
		Board any changes
	•	reviews director compensation and recommends changes to the
		Board
	•	executes the duties, responsibilities and authority set forth in
		the Nominating and Governance Committee Charter
	•	evaluates annually its own performance and the adequacy of its
		charter

AUDIT COMMITTEE	•	periodically meets separately with management, internal auditors	8 Meetings
		and the independent registered public accounting firm to discuss
H. C. Stowe, Chairman*		and evaluate the scope and results of audits and SCANA's
W. C. Burkhardt		accounting procedures and controls
D. M. Hagood	•	reviews major issues regarding accounting principles and financial
L. M. Miller		statement preparation
M. K. Sloan	•	reviews SCANA's financial statements before submission to the
		Board for approval, prior to dissemination to shareholders, the
		public or regulatory agencies
	•	selects (for ratification by the shareholders) the independent
		registered public accounting firm
	•	sets compensation of independent registered public accounting firm
	•	oversees 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	5 Meetings
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
W. C. Burkhardt		training 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 Board has determined that Mr. Stowe is an "audit committee financial expert" as defined under Item 401(h) of the Securities and Exchange Commission's Regulation S-K. Mr. Stowe is independent as that term is used in 7(d)(3)(iv) of Schedule 14A of the Proxy Rules under the Securities Exchange Act of 1934.

GOVERNANCE INFORMATION

Governance Principles

Our governance principles can be found on SCANA's website at www.scana.com under the "Investor Information—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 and Governance 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 financial 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.

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 and 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 and Governance Committee recommended to the Board the individuals nominated for director positions at the 2006 Annual Meeting. All of the members of the Nominating and Governance Committee are independent as independence is defined for nominating committee members under the New York Stock Exchange Listing Standards.

The Nominating and Governance Committee will consider for recommendation to the Board as Board of Directors' nominees candidates recommended by shareholders if the shareholders comply with the following requirements. If a shareholder wishes to recommend a candidate to the Nominating and Governance Committee for consideration as a Board of Directors' nominee, such shareholder must submit in writing to the Nominating and Governance Committee the recommended candidate's name, a brief resume setting forth the recommended candidate's business and educational background and qualifications for

service, and a notarized consent signed by the recommended candidate stating the recommended candidate's willingness to be nominated and to serve. This information must be delivered to the SCANA Nominating and Governance Committee, c/o the Corporate Secretary at the Company's address and must be received no later than 120 days prior to the first anniversary of the date of the proxy statement sent to shareholders in connection with the preceding year's annual meeting for a potential candidate to be considered as a potential Board of Directors' nominee. The Nominating and Governance Committee may request further information if it determines a potential candidate may be an appropriate nominee. Director candidates recommended by shareholders that comply with these requirements will receive the same consideration that the Nominating and Governance Committee's candidates receive.

Director candidates recommended by shareholders will not be considered for recommendation by the Nominating and Governance Committee as potential Board of Directors' nominees if the shareholder recommendations are received later than 120 days prior to the first anniversary of the date of the proxy statement sent to shareholders in connection with the preceding year's annual meeting. If the Nominating and Governance Committee chooses not to recommend a shareholder candidate as a Board of Directors' nominee, or if a shareholder chooses to personally nominate a candidate 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 Corporate Secretary of SCANA 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 and Governance Committee Charter directs the committee to take into account applicable requirements for directors under the Securities Exchange Act of 1934, the listing standards of the New York Stock Exchange and director qualification standards in SCANA's Governance Principles, including SCANA's policy that a majority of its directors be independent.

The 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, diversity, 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, 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 the highest personal and professional ethics and integrity and values consistent with those of SCANA.
•: 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 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.
•: Directors are required to retire from the Board at the annual meeting of shareholders in the year preceding their reaching the age of 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 expected of each Board member and will be evaluated by the Nominating and Governance Committee in the course of its work.

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 "Investor Information—Code of Conduct & Ethics" 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.

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

Shareholders 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). Shareholders may also communicate with the chair of the following SCANA committees by sending an e-mail to: auditchair@scana.com, humanresourceschair@scana.com, or nomgovchair@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.

DIRECTOR COMPENSATION

Board Fees

The Board reviews director compensation annually with guidance from the Nominating and Governance Committee. In making its recommendations, the Committee is required by SCANA's Governance Principles to consider that compensation should fairly pay directors for work required in a company of SCANA's 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.

Officers of SCANA 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;
•: 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 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 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.

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 Plan. Amounts deferred by directors in previous years under the SCANA Voluntary Deferral Plan continue to be governed by that plan. During 2005, the only director remaining in the Voluntary Deferral Plan was Mr. Bennett, whose account was credited with interest of $4,345 for the year.

Under the Director Compensation and Deferral Plan, a director may elect to defer the annual retainer fee, which (effective January 1, 2006) is required to be paid in SCANA common stock, in a hypothetical investment in SCANA common stock, with distribution from the plan to be ultimately payable in actual shares of SCANA 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 SCANA common stock or cash. Amounts payable in SCANA common stock accrue earnings during the deferral period at SCANA's dividend rate, which amount may be elected to be paid in cash when accrued or retained to invest in additional hypothetical shares of SCANA common stock. Amounts payable in cash accrue interest until paid.

During 2005, Messrs. Amick, Bennett, Burkhardt, Hipp, Sloan, York and Ms. Miller elected to defer 100% of their compensation and earnings under the Director Compensation and Deferral Plan so as to acquire hypothetical shares of SCANA common stock.

Endowment Plan

Upon election to a second term, a director becomes eligible to participate in the SCANA Director Endowment Plan, which provides for SCANA to make tax deductible, charitable contributions totaling $500,000 to institutions of higher education designated by the director. The plan is intended to reinforce SCANA's commitment to quality higher education and to enhance its 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. The plan is funded in part through insurance on the lives of the directors.

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.

Other

During 2005 the Company provided William B. Bookhart, Jr. (deceased November 21, 2005) and his wife with health care benefits having a value of $5,773 in excess of Mr. Bookhart's contribution. No other non-management directors received health care benefits from the Company in 2005.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

During 2005, decisions on various elements of executive compensation were made by the Human Resources Committee. No officer, employee or former officer of SCANA or any of its subsidiaries served as a member of the Human Resources Committee.

The names of the directors who serve on the Human Resources Committee are:

W. C. Burkhardt, Chairman
B. L. Amick
J. A. Bennett
D. M. Hagood
M. K. Sloan

RELATED TRANSACTIONS

Prior to its acquisition in January 2006, Mr. Hipp was Chairman and Chief Executive Officer and a director of The Liberty Corporation. During 2005, SCANA incurred advertising expenses of approximately $29,906 (including the value of non-utility in-kind services provided by SCANA and its subsidiaries) for services provided by subsidiaries of The Liberty Corporation. SCANA's management believes that these services, a significant portion of which were arranged through the use of an independent third-party advertising agency, were provided at competitive market rates.

SHARE OWNERSHIP OF DIRECTORS, NOMINEES AND EXECUTIVE OFFICERS

In general, shares "beneficially owned" are shares a person has the power to vote or transfer or shares as to which a person has the power to direct the vote or transfer.

The following table lists shares beneficially owned on March 10, 2006, by each director, each nominee and each person named in the Summary Compensation Table on page 18.

Name		Amount and Nature of Beneficial Ownership of SCANA Common Stock^{(1)(2)(3)(4)(5)}	Percent of Class
B. L.	Amick	11,016	*
J. A.	Bennett	2,603	*
G. J.	Bullwinkel	81,135	*
W. C.	Burkhardt	13,121	*
S. A.	Byrne	52,453	*
S. A.	Decker	1,112	*
D. M.	Hagood	1,540	*
W. H.	Hipp	14,058	*
N. O.	Lorick	20,021	*
K. B.	Marsh	18,902	*
L. M.	Miller	3,666	*
M. K.	Sloan	1,831	*
H. C.	Stowe	2,732	*
W. B.	Timmerman	181,865	*
G. S.	York	13,204	*
Directors and Executive Officers as a group (21 persons)⁽⁶⁾			.4	%

* Each of the above named individuals owns less than 1% of the shares outstanding.

(1): Includes 182 shares owned by close relatives of Mr. Lorick.
(2): Includes shares purchased through March 10, 2006, by the Trustee under SCANA's Stock Purchase Savings Plan.
(3): Hypothetical shares acquired under the Director Compensation and Deferral Plan are not included in the above table. As of March 10, 2006, each of the following directors had acquired under the plan the number of hypothetical shares following his or her name: Messrs. Amick — 13,091; Bennett — 13,171; Burkhardt — 16,074; Hagood — 4,089; Hipp — 11,527; Sloan — 14,490; Stowe — 11,538; York — 14,750; Mrs. Decker — 0; and Ms. Miller — 15,357.
(4): Includes shares subject to options that are currently exercisable or that will become exercisable within 60 days in the following amounts: Messrs. Timmerman — 123,067; Bullwinkel — 45,279; Byrne — 42,992.
(5): Hypothetical shares acquired under the Executive Deferred Compensation Plan are not included in the above table. As of March 10, 2006, each of the following officers had acquired under the plan the number of hypothetical shares following his name: Messrs. Timmerman — 37,768; Bullwinkel — 17,142; Byrne — 7,034; Lorick — 10,194; and Marsh — 4,946.
(6): Includes 218,106 shares subject to options held by executive officers that are currently exercisable or that will become exercisable within 60 days.

FIVE PERCENT 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 March 10, 2006. 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 AMVESCAP National Trust Company, as Trustee 400 Colony Square, Suite 2200 1201 Peachtree Street, N.E. Atlanta, GA 30361		11,215,683	⁽¹⁾	9.8	%
JPMorgan Chase & Co.⁽²⁾ 270 Park Ave New York, NY 10017		6,140,486		5.3	%

(1): The SPSP has shared power to vote and dispose of all of the shares reported as owned.
(2): JPMorgan Chase & Co. is a parent holding company that has subsidiaries which beneficially hold the shares on behalf of themselves or others.

EXECUTIVE COMPENSATION

Summary Compensation Information

The following table contains information with respect to compensation paid or accrued during the years 2005, 2004 and 2003, to the Chief Executive Officer of SCANA and the other four most highly compensated persons who were executive officers of SCANA during 2005.



SUMMARY COMPENSATION TABLE


		Annual Compensation			Long-Term Compensation Awards

Name and Principal Position	Year	Salary ($)		Bonus⁽¹⁾ ($)	LTIP Payouts⁽²⁾ ($)	All Other Compensation⁽³⁾ ($)

W. B. Timmerman Chairman, President, Chief Executive Officer and Director — SCANA Corporation	2005 2004 2003	997,654 931,583 858,219	⁽⁴⁾	1,278,443 948,494 718,493	1,509,703 0 1,150,242	124,560 108,828 102,904
N. O. Lorick President and Chief Operating Officer — South Carolina Electric & Gas Company	2005 2004 2003	498,077 470,833 419,808		487,500 378,625 300,036	535,875 0 325,384	60,674 55,324 50,219
K. B. Marsh Senior Vice President and Chief Financial Officer — SCANA Corporation	2005 2004 2003	498,077 470,833 419,808		487,500 378,625 300,036	535,875 0 325,384	53,884 48,534 45,185
G. J. Bullwinkel President and Chief Operating Officer — SCANA Energy Marketing, Inc.	2005 2004 2003	424,231 389,583 346,411		318,750 247,625 212,575	428,820 0 169,634	45,570 42,200 35,286
S. A. Byrne Senior Vice President — Generation, Nuclear and Fossil Hydro South Carolina Electric & Gas Company	2005 2004 2003	399,216 362,728 323,351		300,300 225,660 180,675	296,099 0 169,634	48,909 33,366 30,993

(1): Payments under the Short-Term Annual Incentive Plan.
(2): Payouts of performance share awards and performance unit awards under the Long-Term Equity Compensation Plan.
(3): All other compensation for the named executive officers consists of matching contributions to defined contribution plans and life insurance premiums on policies owned by named executive officers. The following are premium amounts for 2005: Messrs. Timmerman — $7,791; Bullwinkel — $5,259; Byrne — $0; Lorick — $8,072; and Marsh — $1,282. The following are matching contribution amounts for 2005: Messrs. Timmerman — $116,769; Bullwinkel — $40,311; Byrne — $48,909; Lorick — $52,602; and Marsh — $52,602.
(4): Reflects actual salary earned in 2005. Base salary of $1,002,700, as referenced on page 25, became effective on February 17, 2005.

Option Exercises, Outstanding Options and Related Information

Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values

				Number of Securities Underlying Unexercised Options/SARs At FY-End (#)	Value of Unexercised In-the-Money Options/ SARs at FY-End($)⁽²⁾
Name	Shares Acquired On Exercise (#)	Value Realized ($)⁽¹⁾		Exercisable/ Unexercisable	Exercisable/ Unexercisable
W. B. Timmerman	0	$	0	123,067/0	$	1,459,575/0
N. O. Lorick	25,939		295,185	0/0		0/0
K. B. Marsh	25,939		297,779	0/0		0/0
G. J. Bullwinkel	0		0	45,279/0		519,291/0
S. A. Byrne	27,938		317,369	42,992/0		509,885/0

(1): The difference between the exercise prices paid and the closing prices of SCANA common stock on the exercise dates.
(2): Based on the closing price of $39.38 per share on December 30, 2005, the last trading day of the fiscal year, and exercise prices ranging from $27.45 to $29.60 per share.

Long-Term Incentive Plan Awards

The following table lists the performance share awards made in 2005 (for potential payment in 2008) under the Long-Term Equity Compensation Plan and estimated future payouts under that plan at threshold, target and maximum levels for each of the executive officers included in the Summary Compensation Table.

Long-Term Incentive Plans
Awards in Last Fiscal Year

			Estimated Future Payouts Under Non-Stock Price-Based Plans
		Performance or Other Period Until Maturation or Payout	Estimated Future Payouts Under Non-Stock Price-Based Plans
Name	Number of Shares, Units or Other Rights (#)	Performance or Other Period Until Maturation or Payout	Threshold (#)	Target (#)	Maximum (#)
W. B. Timmerman	71,558	2005-2007	35,779	71,558	107,337
N. O. Lorick	22,302	2005-2007	11,151	22,302	33,453
K. B. Marsh	22,302	2005-2007	11,151	22,302	33,453
G. J. Bullwinkel	12,890	2005-2007	6,445	12,890	19,335
S. A. Byrne	12,144	2005-2007	6,072	12,144	18,216

Payout of performance share awards will be dictated by SCANA's performance against pre-determined measures of total shareholder return and growth in earnings per share over the three year plan cycle.

Sixty percent of target performance share awards are based on SCANA's total shareholder return ("TSR") over the three-year plan cycle compared with a peer group. The peer group of companies is the same group used in the Performance Graph on page 27. TSR is calculated by dividing stock price increase 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. No payout is earned if performance is less than the 33rd percentile. Executives earn threshold payouts (50% of target award) if SCANA ranks at the 33rd percentile in relation to the peer group's three-year TSR performance. Target payouts (100% of target award) occur if SCANA ranks at the 50th percentile in relation to the peer group's three-year TSR performance. Maximum payouts (150% of target award) result if SCANA's performance ranks at or above the 75th percentile in relation to the peer group's three-year TSR performance.

Forty percent of target performance share awards are based on meeting SCANA's projections for three-year growth in earnings per share ("EPS") from ongoing operations. Payouts vary according to projection achievement. No payout is earned if EPS growth is less than the minimum pre-established growth projection. Executives earn threshold payouts (50% of target award) upon achievement of the minimum three-year EPS growth projection. Target payouts (100% of target award) occur if SCANA achieves the target three-year EPS growth projection. Maximum payouts (150% of target award) result if SCANA's performance is at or above the maximum three-year EPS growth projection.

Payments are calculated using a sliding scale for performance between threshold and target and target and maximum levels. 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.

Defined Benefit Plans

SCANA sponsors a tax qualified defined benefit retirement plan (the "Retirement Plan"). The Retirement Plan utilizes 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 executive officers named in the Summary Compensation Table elected to 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.

In addition to its Retirement Plan for all employees, SCANA provides Supplemental Executive Retirement Plans ("SERPs") for certain eligible employees, including officers. A SERP is an unfunded plan that provides for benefit payments in addition to benefits payable under the qualified Retirement Plan in order to replace benefits lost in the Retirement Plan because of Internal Revenue Code maximum benefit limitations.

The estimated annual retirement benefits payable as life annuities at age 65 under the Retirement Plan and SERPs, based on projected compensation (assuming increases of 4% per year), to the executive officers named in the Summary Compensation Table are as follows: Mr. Timmerman — $464,640; Mr. Lorick — $297,456; Mr. Marsh — $368,232; Mr. Bullwinkel — $291,864; and Mr. Byrne — $299,820.

Termination, Severance and Change in Control Arrangements

SCANA maintains an Executive Benefit Plan Trust. The purpose of the trust is to help retain and attract quality leadership in key SCANA positions. The trust holds SCANA contributions (if made) which may be used to pay the deferred compensation benefits of certain directors, executives and other key employees of SCANA in the event of a Change in Control (as defined in the trust). The current executive officers included in the Summary Compensation Table participate in all the plans listed below which are covered by the trust:

(1): Executive Deferred Compensation Plan
(2): Supplemental Executive Retirement Plan
(3): Long-Term Equity Compensation Plan
(4): Short-Term Annual Incentive Plan
(5): Key Executive Severance Benefits Plan
(6): Supplementary Key Executive Severance Benefits Plan

The Key Executive Severance Benefits Plan and each of the plans listed under (1) through (4) provide for payment of benefits in a lump sum to the eligible participants immediately upon a Change in Control, unless the Key Executive Severance Benefits Plan is terminated prior to the Change in Control. In contrast, the Supplementary Key Executive Severance Benefits Plan is intended to be operative for a period of 24 months following a Change in Control in which the Key Executive Severance Benefits Plan is inoperative because it was terminated before the Change in Control. The Supplementary Key Executive Severance Benefits Plan provides benefits if: (i) the participant is involuntarily terminated from employment without "Just Cause," or (ii) the participant voluntarily terminates employment for "Good Reason" (as these terms are defined

in the Supplementary Key Executive Severance Benefits Plan).

Benefit distributions relative to a Change in Control, as to which either the Key Executive Severance Benefits Plan or the Supplementary Key Executive Severance Benefits Plan is operative, include an amount equal to estimated federal, state and local income taxes and any estimated applicable excise taxes owed by plan participants on those benefits.

The benefit distributions under the Key Executive Severance Benefits Plan would include the following three benefits:

•: An amount equal to three times the sum of: (i) the participant's annual base salary in effect as of the date of the Change in Control and (ii) the officer's target annual incentive award in effect as of the date of the Change in Control under the Short-Term Annual Incentive Plan.
•: 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 the participant had continued to be a SCANA employee.
•: An amount equal to the participant's Supplemental Executive Retirement Plan benefit accrued to the date of the Change in Control, increased by the present value of projected benefits that would otherwise accrue under the plan (based on the plan's actuarial assumptions) assuming that the participant remained employed until reaching age 65, and offset by the value of the participant's Retirement Plan benefit.

Additional benefits payable upon a Change in Control in which the Key Executive Severance Benefits Plan is operable are as follows:

•: A benefit distribution of all amounts credited to the participant's Executive Deferred Compensation Plan 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.
•: Under the Long-Term Equity Compensation Plan, all nonqualified stock options awarded would become immediately exercisable and remain exercisable throughout their original term.
•: 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.

The benefits and their respective amounts under the Supplementary Key Executive Severance Benefits Plan would be the same as those described above, except that the benefits payable with respect to the Executive Deferred Compensation Plan would be increased by the prime rate published in the Wall Street Journal most nearly preceding the date of the Change in Control plus 3% calculated until the end of the month preceding the month in which the benefits are distributed.

REPORT ON EXECUTIVE COMPENSATION

SCANA's executive compensation program is designed to support SCANA's overall objective of creating shareholder value by:

•: Hiring and retaining premier executive talent;
•: Having a pay-for-performance philosophy linking total rewards to achievement of corporate and business unit goals;
•: Placing a substantial portion of pay for senior executives "at-risk" and aligning the interests of executives with the long-term interests of shareholders through equity-based compensation; and
•: Balancing elements of the compensation program to reflect SCANA's financial, customer-oriented and strategic goals.

We believe our program performs a vital role in keeping our executives focused on enhancing shareholder value.

A description of the program and a discussion of Mr. Timmerman's 2005 compensation follows.

Program Elements

During 2005, executive compensation consisted primarily of three key components: base salary, short-term incentive compensation (under the Short-Term Annual Incentive Plan) and long-term incentive compensation (under the Long-Term Equity Compensation Plan).

Market survey results along with internal equity are considered when establishing target compensation levels. Compensation levels are reviewed annually against the 50th percentile of market data gathered from utilities and general industry companies of various sizes. Results are adjusted through regression analysis to account for differences in company size. Companies in the 2005 peer group shown on page 27 for which survey results are available are included in the market comparison group.

The specific components of SCANA's compensation program for executive officers are described more fully in the following paragraphs. Each component of the compensation package, including severance plans, insurance and other benefits, is considered in determining total compensation.

Base Salaries

Executive base salaries are reviewed annually by the Human Resources Committee. Adjustments are made on the basis of an assessment of individual performance, relative levels of accountability, prior experience, breadth and depth of knowledge and changes in market compensation practices.

Short-Term Annual Incentive Plan

SCANA's Short-Term Annual Incentive Plan promotes SCANA's pay-for-performance philosophy, as well as its goal of having a meaningful amount of executive pay "at-risk." This plan provides financial incentives for performance in the form of an opportunity for annual cash bonuses.

Target bonus levels are set at the beginning of each year. Actual bonus awards are based on the level of performance achieved. If annual performance results in a bonus distribution, target award payouts can be adjusted to provide a more accurate reflection of performance. Adjustments to target award payouts may increase or decrease award levels by no more than fifty percent. Awards earned based on the achievement of pre-established goals may nonetheless be decreased or eliminated if the Human Resources Committee determines that actual results warrant a lower payout.

For 2005, the Short-Term Annual Incentive Plan placed equal emphasis on achieving profitability targets and annual business objectives relating to such matters as efficiency,

quality of service, customer satisfaction, safety and progress toward SCANA's strategic objectives. The plan allows for an adjustment of an award based upon an evaluation of individual performance. Each award may be increased or decreased by no more than 20% based on the individual performance evaluation, but in no case may an award exceed the maximum payout of 1.5 times target.

Due to SCANA's accomplishment of its profitability targets and its annual business objectives for 2005, participants in the plan received payouts for 2005.

Long-Term Equity Compensation Plan

The potential value of long-term incentive opportunities comprises a significant portion of the total compensation package for officers and key employees. The Human Resources Committee believes this approach to total compensation provides the appropriate focus for those officers and other key employees who are charged with the responsibility for managing the Company and achieving success for SCANA's shareholders. A portion of each executive's potential compensation consists of awards under the Long-Term Equity Compensation Plan. Long-term awards available to the committee under the plan include incentive and nonqualified stock options, stock appreciation rights (either alone or in tandem with a related option), restricted stock, performance units and performance shares. Certain of these awards may be granted subject to satisfaction of specific performance goals. For the 2005-2007 performance period, awards under the Long-Term Equity Compensation Plan consisted solely of performance shares.

Performance Share Awards

SCANA's performance share awards under the Long-Term Equity Compensation Plan pay bonuses to executives based on SCANA's Total Shareholder Return ("TSR") relative to a group of peer companies over a three-year period and on SCANA's growth in earnings per share ("EPS") from ongoing operations. The purpose of performance share awards is to ensure that executives are compensated only when shareholders gain.

TSR is stock price increase over the three-year period, plus cash dividends paid during that period, divided by stock price as of the beginning of the period. Comparing SCANA's TSR to the TSR of a group of other companies reflects SCANA's recognition that investors could have invested their funds in other entities, and measures how well SCANA performed when compared to others in the group.

2005 Payouts Under Performance Share Awards and Performance Unit Awards Granted in 2003

Performance Share Awards

Under target performance share awards granted in 2003 for the 2003-2005 performance period, payouts were set to occur when SCANA's TSR was in the top two-thirds of the Long-Term Equity Compensation Plan peer group over the period. For purposes of the 2003-2005 performance period, the peer group was comprised of SCANA and the 43 other electric and gas utilities listed on page 27, none of which have revenues of less than $100 million. Executives would earn threshold payouts (50% of award) if SCANA ranked at the 33rd percentile in relation to the peer group's three-year TSR performance. Target payouts (100% of award) would be earned if SCANA ranked at the 50th percentile in relation to the peer group's three-year TSR performance. Maximum payouts (150% of award) would be earned if SCANA ranked at or above the 75th percentile in relation to the peer group's three-year TSR performance. No payouts would be earned if TSR were at less than the 33rd percentile.

For the three-year performance period 2003-2005, SCANA's TSR was at the 36th

percentile of the peer group's TSR which resulted in cash payouts at 59% of the target for the period.

Performance Unit Awards

Under target performance unit awards granted in 2003 for the 2003-2005 performance period, payouts were set to occur when SCANA's three-year average growth in EPS from ongoing operations equaled or exceeded 4%. Executives would earn threshold payouts (50% of award) at 4% average growth, target payouts (100% of award) at 6% average growth and maximum payouts (150% of award) at 8% average growth. No payouts would occur if average growth in EPS from ongoing operations over the period were less than 4%.

For the three-year performance period 2003-2005, SCANA's average growth in EPS was 5.3%, which resulted in cash payouts at 82.5% of the target for the period.

Policy with Respect to the $1 Million Deduction Limit

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 executive officers. Certain performance-based compensation approved by shareholders is not subject to the deduction limit. SCANA's Long-Term Equity Compensation Plan is qualified so that most performance-based awards under that plan constitute compensation not subject to Section 162(m). To maintain flexibility in compensating 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.

2005 Compensation of Chief Executive Officer

For 2005, Mr. Timmerman's compensation consisted of the following:

•: Base salary of $1,002,700 derived by reference to executive pay for the peer group described on page 23. Mr. Timmerman's salary increase was also based on his responsibilities as Chairman and Chief Executive Officer and the Human Resources Committee's assessment of his overall performance during the preceding year. Because this determination was subjective, no one factor was assigned a particular weighting by the committee.
•: For the year 2005, Mr. Timmerman's Short-Term Annual Incentive Plan target award was 85% of Mr. Timmerman's 2005 base salary and was based on three factors: SCANA EPS, achievement of strategic plan objectives and the Human Resources Committee's subjective assessment of his individual performance. Performance in these factors resulted in Mr. Timmerman receiving a payout of 150% of target for the 2005 performance period.
•: In 2005, Mr. Timmerman's Long-Term Equity Compensation Plan target was set at 200% of his base salary. This resulted in an award of 71,558 performance shares for the 2005-2007 performance period. The amount of the award was determined by the Human Resources Committee based on Mr. Timmerman's salary, level of responsibility and competitive practices.

•: As discussed above, SCANA's TSR for the 2003-2005 performance period was at the 36th percentile of the peer group's TSR for the three-year period, which resulted in a payout of performance share awards to Mr. Timmerman at 59% of the target. SCANA's average EPS growth for the 2003-2005 period was 5.3%, which resulted in a payout of performance unit awards to Mr. Timmerman at 82.5% of the target.

Human Resources Committee

W. C. Burkhardt, Chairman
B. L. Amick
J. A. Bennett
D. M. Hagood
M. K. Sloan

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.

The Performance Graph, Audit Committee Report and Report on Executive Compensation in this proxy statement are not incorporated by reference into any other filings with the Securities and Exchange Commission.

PERFORMANCE GRAPH

The line graph on page 28 compares the cumulative TSR on SCANA common stock, assuming reinvestment of dividends, with the S&P Utilities Index, the S&P 500 Index and a group of peer issuers. SCANA includes the peer group index in its 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 2005 Peer Group are weighted according to the respective issuer's stock market capitalization at the beginning of each period.

The 2005 Peer Group index consists of SCANA and the following companies:

2005 Peer Group

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

Note: NorthWestern Corporation emerged from bankruptcy in November 2004; however, their information is not reflected in the performance graph because there is not a full five year period history of their stock price and dividends.

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, 2000, in SCANA common stock, the 2005 Peer Group and the S&P Indices.

*Total return assumes reinvestment of dividends.

AUDIT COMMITTEE REPORT

The Board has adopted an Audit Committee Charter. The charter can be found on SCANA's web site at www.scana.com under the "Investor Information—Corporate Governance" caption. Under its charter, the Audit Committee is responsible for, among other things, the appointment of the independent registered public accounting firm (the "independent auditors"); reviewing with the independent auditors, and approving, the plan and scope of the audit and audit fees; monitoring the adequacy of reporting and internal controls; and meeting periodically, separately, with management, the internal auditors and the independent auditors. All the members of the Audit Committee are independent as independence is defined for audit committee members in the New York Stock Exchange Listing Standards.

In connection with the December 31, 2005 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 Statement on Auditing Standards ("SAS") No. 61 (as amended by SAS 89 and 90) and the New York Stock Exchange Corporate Governance Rules, and (iii) received from the independent auditors the written disclosures and the letter required by Independence Standards Board Statement No.1, and has discussed with the independent auditors the independent auditors' independence. Based upon these reviews and discussions, the Audit Committee recommended to the Board, and the Board approved, that SCANA's audited financial statements be included in SCANA's Annual Report on Form 10-K for the fiscal year ended December 31, 2005, for filing with the Securities and Exchange Commission.

The Audit Committee

Harold C. Stowe, Chairman
William C. Burkhardt
D. Maybank Hagood
Lynne M. Miller
Maceo K. Sloan

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

The Audit Committee has appointed Deloitte & Touche LLP as SCANA's independent registered public accounting firm to audit SCANA's 2006 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 and Touche's 2006 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 2006 financial statements. Deloitte & Touche LLP audited the financial statements included in this proxy statement.

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.

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, 2005 and 2004 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu and their respective affiliates.

	2005		2004
Audit Fees⁽¹⁾	$	2,144,848	$	2,219,405
Audit Related Fees⁽²⁾		94,082		67,558
Tax Fees⁽³⁾		94,345		78,088
All Other Fees		0		0

Total Fees	$	2,333,275	$	2,365,051

(1): Fees for Audit Services billed for 2005 and 2004 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 2005 and 2004.
(3): Fees for tax compliance and tax research services.

In 2005 and 2004, 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 and written representations made to SCANA, all filings on behalf of such persons were made on a timely basis in 2005. The following Director of SCANA filed one late Form 4: Mr. William C. Burkhardt (8 transactions).

Shareholder Proposals and Nominations

In order to be considered for inclusion in SCANA's proxy statement and proxy card for the 2007 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 17, 2006. 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 2007 Annual Meeting, must notify SCANA no later than November 17, 2006 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 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 Shareholder Communications, 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.

Tickets to the Annual Meeting

An admission ticket to the meeting is enclosed. 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 an 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 10, 2006 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 10, 2006.

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, 2005. 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

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.

SCANA CORPORATION

Lynn M. Williams
Corporate Secretary
March 17, 2006

FINANCIAL APPENDIX

		Page
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	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
	Market for Registrant's Common Equity and Related Stockholder Matters	F-68
	Executive Officers	F-69
	Certifications	F-69

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,			2005		2004		2003		2002		2001
Statement of Operation Data
	Operating Revenues		$4,777		$3,885		$3,416		$2,954		$3,451
	Operating Income		436		596		551		514		528
	Other Income (Expense)		(162	)	(219	)	(138	)	(397	)	309
	Income Before Cumulative Effect of Accounting Change		320		257		282		88		539
	Net Income (Loss)⁽¹⁾		320		257		282		(142	)	539
Common Stock Data
	Weighted Average Number of Common Shares Outstanding (Millions)		113.8		111.6		110.8		106.0		104.7
	Basic and Diluted Earnings (Loss) Per Share⁽¹⁾		$2.81		$2.30		$2.54		$(1.34	)	$5.15
	Dividends Declared Per Share of Common Stock		$1.56		$1.46		$1.38		$1.30		$1.20
Balance Sheet Data
	Utility Plant, Net		$6,734		$6,762		$6,417		$5,474		$5,263
	Total Assets		9,519		9,006		8,458		8,074		7,822
	Capitalization:
		Common equity	$2,677		$2,451		$2,306		$2,177		$2,194
		Preferred Stock (Not subject to purchase or sinking funds)	106		106		106		106		106
		Preferred Stock, net (Subject to purchase or sinking funds)	8		9		9		9		10
		SCE&G — Obligated Mandatorily Redeemable Preferred Securities of SCE&G Trust I	—		—		—		50		50
		Long-term Debt, net	2,948		3,186		3,225		2,834		2,646

		Total Capitalization	$5,739		$5,752		$5,646		$5,176		$5,006

Other Statistics
	Electric:
		Customers (Year-End)	609,971		585,264		570,940		560,224		547,388
		Total sales (Million KWh)	25,140		25,031		22,516		23,085		22,928
		Generating capability — Net MW (Year-End)	5,808		5,817		4,880		4,866		4,520
		Territorial peak demand — Net MW	4,820		4,574		4,474		4,404		4,196
	Regulated Gas:
		Customers (Year-End)	714,794		693,172		672,849		657,950		647,988
		Sales, excluding transportation (Thousand Therms)	1,106,526		1,124,555		1,205,730		1,354,400		1,183,463
	Retail Gas Marketing:
		Retail customers (Year-End)	479,382		472,468		415,573		374,872		385,581
		Firm customer deliveries (Thousand Therms)	379,913		379,712		356,256		337,858		359,602
	Nonregulated Interruptible Customer Deliveries (Thousand Therms)		1,010,066		917,875		735,902		852,608		1,119,719

(1): In 2002, reflects write-down of $230 million for goodwill impairment, recorded as the cumulative effect of an accounting change, on adoption of SFAS 142.

Significant events affecting historical earnings trends include the following:

In 2005 SCANA Corporation (SCANA, and together with its subsidiaries, the Company) 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). 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

F-2

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, SCANA recorded as the cumulative effect of an accounting change an impairment 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.

In 2001 SCANA exchanged its shares of Powertel, Inc. for shares of DTAG and recognized a gain of $354 million or $3.38 per share. SCANA also sold its home security business and recognized a gain of $4.6 million or $.04 per share. Also in 2001, SCANA recognized impairment losses on telecommunications and other investments of $44 million or $.42 per share.

F-3

SCANA'S BUSINESS

SCANA, through its wholly-owned regulated subsidiaries, is primarily engaged in the generation, transmission and distribution 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.

Regulated Utilities

South Carolina Electric & Gas Company (SCE&G) is a public utility engaged in the generation, transmission, distribution and sale of electricity and in the purchase, sale and transport at retail of natural gas. SCE&G's business is subject to seasonal fluctuations. Generally, sales of electricity are higher during the summer and winter months because of air conditioning and heating requirements, and sales of natural gas are higher in the winter months due to heating requirements. SCE&G's electric service area extends into 26 counties covering more than 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 34 of the 46 counties in South Carolina and covers more than 22,000 square miles. The total population of the counties representing the combined service area is more than 3.0 million. Resale customers include municipalities, electric cooperatives, other investor-owned utilities, registered marketers and federal and state electric agencies. Predominant industries in the areas 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 and operates the A.M. Williams Generating Station (Williams Station) and sells electricity solely to SCE&G.

South Carolina Fuel Company (Fuel Company) acquires, owns and provides financing for SCE&G's nuclear fuel, fossil fuel and sulfur dioxide emission allowance requirements.

PSNC Energy is a public utility engaged primarily in purchasing, selling and transporting natural gas to approximately 425,400 residential, commercial and industrial customers (as of December 31, 2005). PSNC Energy provides service to its 28 franchised counties covering approximately 12,000 square miles in North Carolina. The industrial customers of PSNC Energy include manufacturers or processors of textiles, chemicals, ceramics and clay products, glass, automotive products, minerals, pharmaceuticals, plastics, metals, electronic equipment, furniture and a variety of food and tobacco products.

South Carolina Pipeline Corporation (SCPC) is 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 owns liquefied natural gas (LNG) liquefaction and storage facilities. It also supplies natural gas for SCE&G's gas distribution system. Other resale customers include municipalities and county gas authorities and gas utilities. The industrial customers of SCPC are primarily engaged in the

F-4

manufacturing or processing of ceramics, paper, metal, food and textiles.

SCG Pipeline, Inc. (SCG Pipeline) provides interstate transportation services for natural gas to southeastern Georgia and South Carolina. SCG Pipeline transports natural gas from interconnections with Southern Natural at Port Wentworth, Georgia, and from an import terminal owned by Southern LNG, Inc. at Elba Island, near Savannah, Georgia. The endpoint of the pipeline is at the site of SCE&G's Jasper County Electric Generating Station. In 2006, SCANA expects to merge SCPC with SCG Pipeline, subject to closing conditions and Federal Energy Regulatory Commission (FERC) approval.

Nonregulated Businesses

SCANA Energy Marketing, Inc. (SEMI) markets natural gas primarily in the southeast and provides energy-related risk management services. In addition, SCANA Energy, a division of SEMI, markets natural gas to over 475,000 customers (as of December 31, 2005) in Georgia's natural gas market. The Georgia Public Service Commission (GPSC) has contracted with SCANA Energy to serve as regulated provider. Currently, over 70,000 of SCANA Energy's customers are served under the regulated provider contract. This group includes low-income and high credit risk customers. In June 2005 the GPSC voted to retain SCANA Energy as Georgia's regulated provider of natural gas for a two-year period ending August 31, 2007, with an option by the GPSC to extend the term for an additional year. SCANA Energy's total customer base represents about a 30 percent 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 Communications, Inc. (SCI) owns and operates a fiber optic telecommunications network (approximately 500 miles) and data center facilities in South Carolina and, through its joint venture with FRC, LLC, has an interest in an additional 1,064 miles of fiber in South Carolina, North Carolina and Georgia. SCI also provides ethernet services in South Carolina, as well as telecommunications tower site construction, management and rental services in South Carolina and North Carolina.

ServiceCare, Inc. is engaged primarily in providing homeowners with service contracts on their home appliances and heating and air conditioning units.

Primesouth, Inc. is engaged primarily in power plant management and maintenance services. Primesouth is also involved in the operation of a synthetic fuel production facility owned by non-affiliates, and it receives management fees, royalties and expense reimbursements related to those activities.

Service Company

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

F-5

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

Cautionary Language Concerning Forward-Looking Statements

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. 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) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) regulatory actions or changes in the utility and nonutility regulatory environment, (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 the Company's accounting policies, (9) weather conditions, especially in areas served by SCANA's subsidiaries, (10) performance of SCANA's pension plan assets, (11) inflation, (12) changes in environmental regulations, (13) volatility in commodity natural gas markets and (14) the other risks and uncertainties described from time to time in SCANA's periodic reports filed with the Securities and Exchange Commission (SEC). The Company disclaims any obligation to update any forward-looking statements.

OVERVIEW

The activities of the Company's significant business segments are conducted primarily in the areas indicated on the following map, and as further described in this overview section.

F-6

Following are percentages of the Company's revenues and net income earned by regulated and nonregulated businesses and the percentage of total assets held by them.

% of Revenues	2005	2004		2003
Regulated	69%	71 %		73%
Nonregulated	31%	29 %		27%
% of Net Income (Loss)	2005	2004(a)		2003
Regulated	92%	106 %		92%
Nonregulated	8%	(6	)%	8%
% of Assets	2005	2004		2003
Regulated	94%	94 %		93%
Nonregulated	6%	6 %		7%

^(a): 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 recognized on the sale of certain of the Company's telecommunications investments ($29.8 million, net of tax) and a charge related to pending litigation associated with the Company's 1999 sale of its propane assets ($11.1 million, net of taxes). See Results of Operations for more information.

Key earnings drivers for the Company over the next five years will be additions to utility rate base at SCE&G and PSNC Energy, driven primarily by 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, controlling interest expense through continued debt reduction and limiting 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 and distribution of electricity in South Carolina. As of December 31, 2005 SCE&G provided electricity to approximately 610,000 customers in an area covering approximately 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,

F-7

fossil fuel and sulfur dioxide 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. In January 2005, as a result of an electric rate case, SCE&G's allowed return on equity was lowered from 12.45% to an amount not to exceed 11.4%, with rates set at 10.7%. See further discussion at Liquidity and Capital Resources. 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 will monitor 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 in portions of North Carolina and South Carolina. At December 31, 2005 this segment provided natural gas to approximately 717,000 customers in an area covering approximately 34,000 square miles.

Operating results for gas distribution are primarily influenced by customer demand for 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. For SCE&G this allowed return on equity was 12.25% for January 1 through October 31, 2005, when it was lowered to 10.25% as a result of a rate case. For PSNC Energy this allowed return on equity was 11.4% for all of 2005. In the second quarter of 2006, PSNC Energy plans to file with the NCUC a request to increase base rates. Specific details related to the timing and size of the request have not been finalized.

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

F-8

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, 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 did occur in September and October 2005 as a result of 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 are no longer being experienced, 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

For 2005 the gas transmission segment was comprised of SCPC, which owns and operates 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. Operating results are primarily influenced by customer demand for natural gas, the ability to control costs and allowed rates to be charged to customers. Embedded in these rates is an allowed regulatory return on equity, which in 2005 was 12.5% to 16.5%. Demand for natural gas is primarily affected by the price of alternate fuels and customer growth. SCPC supplies natural gas to SCE&G for its resale to gas distribution customers and for certain electric generation needs. SCPC also sells natural gas to large commercial and industrial customers in South Carolina and faces the same competitive pressures as the gas distribution segment for these classes of customers.

In 2006 SCANA expects to merge two of its subsidiaries, SCPC and SCG Pipeline, into a new company to be called Carolina Gas Transmission Corporation (CGTC). CGTC is intended to operate as an open access, transportation-only interstate pipeline company. On February 27, 2006, the merger application was filed with FERC. SCANA does not expect a final decision regarding the merger from FERC before the third quarter of 2006.

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, 2005) throughout Georgia. SCANA Energy's total customer base represents about a 30 percent 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. In addition, the pipeline capacity available for SCANA Energy to serve industrial and other customers is tied to the market share held by SCANA Energy in the retail market.

As Georgia's regulated provider, SCANA Energy serves low-income customers and customers unable to obtain or maintain natural gas service from other marketers at rates approved by the GPSC, and it receives funding from the Universal Service Fund to recoup some of the bad debt associated with the low-income group. In June 2005, the Georgia Public Service Commission (GPSC) voted to retain SCANA Energy as Georgia's regulated provider of natural gas for a two-year period ending

F-9

August 31, 2007, with an option by the GPSC to extend the term for an additional year. In connection with this contract extension, SCANA Energy has agreed to file financial and other information periodically with the GPSC, and such information will be available at www.psc.state.ga.us. At December 31, 2005, SCANA Energy's regulated division served over 70,000 customers.

SCANA Energy and SCANA's other natural gas distribution, transmission 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.

SCANA Energy, pursuant to a written agreement, has maintained a long-standing marketing alliance with Cobb Energy Management Corporation (Cobb Energy), an affiliate of Cobb Electric Membership Corporation (Cobb EMC), and other Georgia electric membership cooperatives (collectively, the EMCs) under the terms of which the parties have worked in an exclusive relationship to attract, retain and serve customers for SCANA Energy. In July 2005, Southern Company Gas, the natural gas marketing affiliate of Southern Company, announced that it had signed a letter of intent to negotiate the sale of its business to a soon to be formed affiliate of Cobb EMC. In connection with this proposed transaction, Cobb Energy, on behalf of itself and the EMCs, entered into discussions with SCANA Energy to modify the marketing alliance.

As a result of those discussions, effective October 31, 2005, SCANA Energy and the EMCs amended the marketing alliance so that, in an orderly fashion in 2006, the EMCs will transition to SCANA Energy certain call center and customer-related administrative functions, such as billing and collections, which are currently being provided to a portion of SCANA Energy's customers by the EMCs. During the process and subsequent to the completion of the transition, certain other requirements also must be met by the EMCs until such time as the marketing alliance expires in October 2008.

SCANA Energy believes that its current customer service and billing systems have the capacity to accommodate the additional customers and that it will have the resources in place to assume responsibility for providing these services for its customers. SCANA Energy expects that the transition will have minimal impact on its customers or related customer service functions. However, as noted above, there can be no assurance that SCANA Energy will be able to maintain its current level of customers, and therefore, no assurance that its current level of profitability will be sustained.

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.

RESULTS OF OPERATIONS

The Company's reported earnings are determined in accordance with GAAP.

F-10

Management believes that, in addition to reported earnings under GAAP, the Company's GAAP-adjusted net earnings from operations provides a meaningful representation of its fundamental earnings power and can aid in performing period-over-period financial analysis and comparison with peer group data. In management's opinion, GAAP-adjusted net earnings from operations is a useful indicator of the financial results of the Company's primary businesses. This measure is also a basis for management's provision of earnings guidance and growth projections, and it is used by management in making resource allocation and other budgetary and operational decisions. 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 operations per share, as well as cash dividend information, is provided in the table below:

		2005			2004		2003
Reported (GAAP) earnings per share		$	2.81		$	2.30	$	2.54
Add (Deduct):
	Gains from sales of telecommunications investments		(.03	)		—		(.35	)
	Losses from sales of telecommunications investments		—			.14		—
	Telecommunications investment impairments		—			.13		.31
	Charge related to pending litigation		—			.10		—

	GAAP-adjusted net earnings from operations per share	$	2.78		$	2.67	$	2.50

	Cash dividends declared (per share)	$	1.56		$	1.46	$	1.38

Discussion of adjustments:

Realized gains (losses) on telecommunications investments of $.03, $(.14) and $.35 were recognized in 2005, 2004 and 2003, respectively, and arose as a result of the Company's orderly monetization of these telecommunications investments. All significant telecommunications investments have now been monetized. The gain of $.03 per share in 2005 resulted from the receipt in 2005 of additional proceeds from the 2003 sale of the Company's investment in ITC Holding. These additional proceeds had been held in escrow pending resolution of certain contingencies. The loss of $.14 per share in 2004 related to the sale of substantially all of the Company's holdings in ITC^DeltaCom and Knology in December of 2004. The gain of $.35 per share in 2003 arose from the sale of the Company's interest in ITC Holding and the receipt of a minority investment interest in a newly formed entity, Magnolia Holding Company, LLC.

The Company's Knology holdings experienced other-than-temporary impairments of $.13 per share in 2004 and $.31 per share in 2003, prior to their monetization in December 2004.

The charge related to pending litigation recognized in 2004 resulted from an unfavorable verdict in a case in which an unsuccessful bidder for the purchase of certain of the Company's propane gas assets in 1999 alleged breach of contract and related claims. Both parties have appealed the judgment. See also Note 10 to the consolidated financial statements.

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 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

F-11

litigation charge 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		2005		2004		2003
Income Statement Impact:
	(Component of) reduction in employee benefit costs	$	4.3	$	2.9	$	(2.3	)
	Other income		11.9		10.8		7.9
Balance Sheet Impact:
	(Component of) reduction in capital expenditures		1.3		1.0		(0.5	)
	Component of (reduction in) amount due to Summer Station co-owner		0.6		0.4		(0.1	)

Total Pension Income		$	18.1	$	15.1	$	5.0

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. Pension income's significant increase in 2004 is consistent with overall investment market results. See also the discussion of pension accounting in Critical Accounting Policies and Estimates.

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 1.4% of income before income taxes in 2005, 6.8% in 2004 and 7.4% in 2003.

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 Generation Station in May 2004 and completion of the Lake Murray Dam project in May 2005.

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. These synthetic fuel production facilities were placed in operation in 2000 and 2001. 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 Dam project as described below.

In a January 2005 order, the SCPSC approved SCE&G's request to apply these synthetic fuel tax credits to offset the construction costs of the Lake Murray Dam project. Under the accounting methodology approved by the SCPSC, 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 is declining 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. In addition, SCE&G is allowed to record non-cash carrying costs on the unrecovered investment. The accelerated depreciation, synthetic fuel tax credits, partnership losses and the income tax

F-12

benefit arising from such losses recognized by SCE&G during 2005 are as follows:

			Recognized
Millions of dollars			4th Quarter 2005			Year Ended December 31, 2005
Depreciation and amortization expense			$	(13.2	)	$	(214.0	)
Income tax benefits:
	From synthetic fuel tax credits			10.9			179.0
	From accelerated depreciation			5.0			81.8
	From partnership losses			1.7			28.9

		Total income tax benefits		17.6			289.7
Losses from Equity Method Investments				(4.4	)		(75.7	)

Impact on Net Income				—			—

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		2005		% Change		2004		% Change		2003
Operating revenues		$	1,908.3	13.1	%	$	1,687.7	15.1	%	$	1,466.5
Less: Fuel used in generation			618.3	32.4	%		466.9	39.7	%		334.1
	Purchased power		37.2	(26.6	)%		50.7	(20.8	)%		64.0

	Margin	$	1,252.8	7.1	%	$	1,170.1	9.5	%	$	1,068.4

•		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 decreased due to greater availability of generation facilities.
•		2004 vs 2003		Margin increased by $47.2 million due to increased off-system sales, by $22.9 million due to increased customer growth and consumption, by $22.3 million due to favorable weather and by $7.1 million due to the increase in retail electric base rates effective February 2003. Fuel used in generation increased by $103.0 million due to increased availability of generation facilities and by $30.0 million due to increased cost of coal. Purchased power decreased due to greater availability of generation facilities.

F-13

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

Classification (in thousands)	2005	% Change		2004	% Change		2003
Residential	7,634	2.3	%	7,460	6.6	%	6,998
Commercial	7,047	2.1	%	6,900	4.4	%	6,607
Industrial	6,651	(1.8	)%	6,775	3.5	%	6,548
Sales for resale (excluding interchange)	1,487	(2.5	)%	1,525	6.1	%	1,438
Other	527	0.2	%	526	5.2	%	500

Total territorial	23,346	0.7	%	23,186	5.0	%	22,091
NMST	1,794	(2.8	)%	1,845	*		425

Total	25,140	0.4	%	25,031	11.2	%	22,516

* Greater than 100%

•		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.
•		2004 vs 2003		Territorial sales volumes increased by 334 MWh and 774 MWh due to customer growth and weather, respectively.

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		2005		% Change		2004		% Change		2003
Operating revenues		$	1,168.6	27.9	%	$	913.9	5.2	%	$	869.0
Less: Gas purchased for resale			894.6	36.6	%		655.1	9.3	%		599.3

	Margin	$	274.0	5.9	%	$	258.8	(4.0	)%	$	269.7

•		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 increased retail gas base rates at SCE&G which became effective with the first billing cycle in November 2005 of $4.6 million. These increases were offset by a $0.8 million decrease due to lower interruptible margin and transportation revenue at SCE&G.
•		2004 vs 2003		Margin decreased primarily due to a decrease in SCE&G's billing surcharge for the recovery of environmental remediation expenses of $5.0 million, lower residential and commercial sales volumes of $2.5 million and milder weather of $5.1 million. This was partially offset by customer growth at PSNC Energy of $4.0 million.

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

Classification (in thousands)	2005	% Change		2004	% Change		2003
Residential	37,860	1.7	%	37,231	(3.4	)%	38,542
Commercial	27,750	1.8	%	27,271	(1.6	)%	27,715
Industrial	20,833	7.8	%	19,320	(3.9	)%	20,109
Transportation gas	27,698	(1.8	)%	28,216	11.1	%	25,387
Sales for resale	—	*		1	*		1

Total	114,141	1.9	%	112,039	0.3	%	111,754

* Not meaningful

•		2005 vs 2004		Commercial and industrial volumes increased primarily due to more customers buying commodity gas instead of purchasing alternate fuels and instead of transporting gas purchased from others.
•		2004 vs 2003		Residential and commercial sales volumes decreased primarily due to unfavorable consumption patterns. Transportation volumes increased primarily as a result of interruptible customers using gas instead of alternate fuels.

Gas Transmission

Gas Transmission is comprised of the operations of SCPC. Gas transmission sales margins (including transactions with affiliates) were as follows:

Millions of dollars		2005		% Change		2004		% Change		2003
Operating revenues		$	658.0	19.4	%	$	550.9	6.0	%	$	519.8
Less: Gas purchased for resale			604.2	21.6	%		496.9	5.2	%		472.2

	Margin	$	53.8	(0.4	)%	$	54.0	13.4	%	$	47.6

•

2005 vs 2004

Operating revenues and gas purchased for resale increased primarily due to higher commodity gas prices.

F-14

•

2004 vs 2003

Margin increased primarily due to higher transportation and reservation revenue as a result of new firm transportation contracts.

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

Classification (in thousands)	2005	% Change		2004	% Change		2003
Commercial	54	(52.2	)%	113	5.6	%	107
Industrial	22,748	(20.5	)%	28,625	(8.9	)%	31,436
Transportation	24,801	(1.8	)%	25,252	*		12,262
Sales for resale	43,763	1.9	%	42,946	(9.4	)%	47,391

Total	91,366	(5.7	)%	96,936	6.3	%	91,196

* Greater than 100%

•		2005 vs 2004		Industrial volumes decreased primarily due to higher commodity gas prices relative to alternate fuels.
•		2004 vs 2003		Industrial volumes decreased primarily due to decreased electric generation. Transportation volumes increased by 7.5 million DTs due to a new contract with a firm transportation customer and by 4.9 million DTs due to new transportation contracts with resale customers. Sales for resale volumes decreased primarily due to the previously mentioned new transportation contracts with resale customers.

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		2005			% Change		2004			% Change		2003
Operating revenues		$	663.8		20.3	%	$	552.0		23.1	%	$	448.3
Net income			24.1		(16.9	)%		29.0		44.3	%		20.1

•		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 (all net of taxes).
•		2004 vs 2003		Operating revenues increased primarily as a result of increased volumes and higher average retail prices. Net income increased primarily due to higher margins of $10.3 million, partially offset by increased bad debt of $1.8 million, increased depreciation expense of $0.4 million and higher customer service expenses of $1.2 million (all net of taxes).

Delivered volumes for 2005, 2004 and 2003 totaled 37.9 million, 37.9 million and 35.6 million DT, respectively.

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		2005			% Change		2004			% Change		2003
Operating revenues		$	945.6		58.5	%	$	596.5		43.5	%	$	415.7
Net loss			(0.6	)	(70.0	)%		(2.0	)	81.8	%		(1.1	)

•		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 (all net of taxes).
•		2004 vs 2003		Operating revenues increased due to higher market prices and higher sales volumes. Net loss increased primarily due to higher operating expenses of $1.2 million partially offset by higher margins of $0.5 million (all net of taxes).

Delivered volumes for 2005, 2004 and 2003 totaled approximately 101.0 million, 91.8 million and 73.6 million DT, respectively. Delivered volumes increased in 2005 compared to 2004 primarily as a result of increased service to municipalities in South Carolina. Delivered volumes increased in 2004 compared to 2003 primarily as a result of the commencement of service to the Jasper County Electric Generating Station in 2004, which created 11.2 million DT of additional volume.

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Other Operating Expenses

Other operating expenses, which arose from the operating segments previously discussed, were as follows:

Millions of dollars	2005		% Change		2004		% Change		2003
Other operation and maintenance	$	632.0	4.0	%	$	607.5	8.8	%	$	558.3
Depreciation and amortization		509.9	92.3	%		265.1	11.2	%		238.3
Other taxes		145.0	(0.4	)%		145.6	4.6	%		139.2

Total	$	1,286.9	26.4	%	$	1,018.2	8.8	%	$	935.8

•		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 long-term bonus and incentive plan expenses of $4.8 million and decreased storm damage expenses of $0.9 million. Depreciation and amortization increased approximately $214.0 million due to accelerated depreciation of the back-up dam at Lake Murray (previously explained at Recognition of Synthetic Fuel Tax Credits), $6.5 million due to the completion of the Jasper County Electric Generating Station in May 2004 and $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 amortized previously deferred purchased power costs and implemented new depreciation rates, resulting in $17.3 million of additional depreciation and amortization expense in the period.
•		2004 vs 2003		Other operation and maintenance expenses increased primarily due to increased labor and benefit expense of $26.3 million, higher bad debt expense of $5.8 million, increased expenses at the generation plants of $11.0 million, winter storm expense of $2.5 million and increased gas marketing and customer billing costs of $4.2 million, partially offset by increased pension income of $5.2 million. Depreciation and amortization increased by $13.4 million due to completion of the Jasper County Electric Generating Station and $11.1 million as a result of normal net property additions. Other taxes increased primarily due to increased property taxes.

Other Income (Expense)

Components of other income (expense), excluding the equity component of AFC, were as follows:

Millions of dollars	2005			% Change		2004			% Change		2003
Gain (loss) on sale of investments	$	7.2		*		$	(21.0	)	*		$	59.8
Gain on sale of assets		1.7		*			0.7		(41.7	)%		1.2
Impairment of investments		—		*			(26.9	)	(49.3	)%		(53.1	)
Other revenues		248.1		36.9	%		181.2		8.6	%		166.8
Other expenses		(200.3	)	25.2	%		(159.9	)	30.2	%		(122.8	)

Total	$	56.7		*		$	(25.9	)	*		$	51.9

* Greater than 100%

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 million loss on the sale of investments in Knology and ITC^DeltaCom. In 2003 a $59.8 million gain on sale of investments was recognized in connection with the sale of ITC Holding and the receipt of a minority interest in a newly formed entity (Magnolia Holding). In 2004, impairments totaling $26.9 million were recorded on Knology, ITC Holding and Magnolia Holding. Impairments in 2003 related to an investment in Knology.

F-16

Interest Expense

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

Millions of dollars	2005		% Change		2004		% Change		2003
Interest on long-term debt, net	$	202.8	(2.5	)%	$	208.1	1.4	%	$	205.2
Other interest expense		12.6	*			4.3	(25.9	)%		5.8

Total	$	215.4	1.4	%	$	212.4	0.7	%	$	211.0

* Greater than 100%

•		2005 vs 2004		Interest on long-term debt decreased primarily due to the redemption of outstanding debt in late 2004. Other interest expense increased primarily due to increased short-term debt at SCE&G.
•		2004 vs 2003		Interest expense increased primarily due to slightly higher levels of borrowing outstanding during 2004 until the payment of maturing debt late in the year.

Income Taxes

Income taxes decreased in 2005 compared to 2004 by $240.8 million and decreased $12.4 million in 2004 compared to 2003. 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.

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, as well as to expand to meet future demand for electricity and gas, 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.

In a January 2005 order, the SCPSC granted SCE&G a composite increase in retail electric rates of approximately 2.89%, designed to produce additional annual revenues of approximately $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 the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray. The SCPSC also approved recovery over a five-year period of SCE&G's approximately $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization and recovery through base rates over three years of approximately $25.6 million of purchased power costs that were deferred under a previous order. 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

F-17

immediately following year, but may not be carried forward indefinitely. No such additional depreciation was recognized in 2005, 2004 or 2003.

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.

SCE&G expects to require the addition of base load electrical generation by 2015 and is evaluating alternatives, including fossil and nuclear-fueled generation. On February 10, 2006, SCE&G and Santee Cooper, a state-owned utility in South Carolina (joint owners of Summer Station) announced their selection of the Summer Station site as the preferred site for a new nuclear plant should nuclear generation be considered the best alternative in the future. Due to the significant lead time required for construction of a nuclear plant, the joint owners are preparing an application to the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL). 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 a nuclear plant. The final decision to build a nuclear plant will be influenced by several factors, including NRC licensing attainment, 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 56% at December 31, 2005. The Company's goal is to reduce this leverage ratio to between 50% and 52%. If the agencies rating the Company's credit determine that the Company will not be able to achieve sufficient improvement in the leverage ratio, among other measures, 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, would increase the rates applicable to the Company's short-term commercial paper programs and long-term debt and would limit the Company's access to capital markets. In order to bring the leverage ratio in line with rating agency expectations, the Company may apply cash flows from operations to debt reduction, sell equity securities, or a combination of the two.

The Company's current estimates of its cash requirements for construction and nuclear fuel expenditures for 2006-2008, which are subject to continuing review and adjustment, are as follows:

Estimated Cash Requirements

Millions of dollars			2006		2007		2008
SCE&G:
	Electric Plant:
		Generation (including GENCO)	$	128	$	86	$	193
		Transmission		50		44		46
		Distribution		115		114		115
		Other		18		11		14
	Nuclear Fuel			27		25		5
	Gas			27		26		31
	Common			22		17		7
	Other			2		—		—

		Total SCE&G		389		323		411
PSNC Energy				70		78		84
Other Companies Combined				44		32		27

		Total	$	503	$	433	$	522

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The Company's contractual cash obligations as of December 31, 2005 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-term and short-term debt (including interest and preferred stock)		$	6,171	$	874	$	925	$	920	$	3,452
Capital leases			2		1		1		—		—
Operating leases			53		15		35		1		2
Purchase obligations			166		152		12		2		—
Other commercial commitments			8,955		1,633		2,207		1,124		3,991

	Total	$	15,347	$	2,675	$	3,180	$	2,047	$	7,445

Included in other commercial commitments are estimated obligations under forward contracts for natural gas purchases. Many of these forward contracts 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.

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 $10.8 million in 2005, 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.

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 1N to the consolidated financial statements.

The Company anticipates that its contractual cash obligations will be met through internally generated funds, issuance of equity under dividend reinvestment and employee stock ownership plans, the incurrence of additional short-term and long-term indebtedness and other sales of equity securities. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future.

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Cash outlays for 2006 (estimated) and 2005 (actual) for certain capital expenditures are as follows:

Millions of dollars		2006		2005
Property additions and construction expenditures, net of AFC		$	485	$	385
Nuclear fuel expenditures			18		18
Investments			18		18

	Total	$	521	$	421

Financing Limits and Related Matters

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

At December 31, 2005 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
		Short-term	$	350			—			—
		Long-term (expires June 2010)		—		$	525		$	125
	Uncommitted			103	^(a)		78	^(a)		—
Short-term borrowings outstanding:
	Bank loans/commercial paper (270 or fewer days)		$	25		$	303.1		$	98.6
	Weighted average interest rate			4.43	%		4.40	%		4.47	%

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

SCANA Corporation

SCANA has in effect a medium-term note program for the issuance from time to time of unsecured medium-term debt securities. While issuance of these securities requires customary approvals discussed above, the Indenture under which they are issued contains no specific limit on the amount which may be issued.

South Carolina Electric & Gas Company

SCE&G's First and Refunding Mortgage Bond Indenture, dated January 1, 1945 (Old Mortgage) and covering substantially all of its properties, prohibits the issuance of additional bonds (Class A Bonds) unless net earnings (as therein defined) for 12 consecutive months out of the 18 months prior to the month of issuance are at least twice (2.00) the annual interest requirements on all Class A Bonds to be outstanding (Bond Ratio). For the year ended December 31, 2005 the Bond Ratio was 7.03. The Old Mortgage allows the issuance of Class A Bonds up to an additional principal amount equal to (i) 70% of unfunded net property additions (which unfunded net property additions certified to the trustee and other property eligible to be certified as property additions totaled approximately $2.0 billion at December 31, 2005), (ii) retirements of Class A Bonds (which retirement credits totaled $86.0 million at December 31, 2005), and (iii) cash on deposit with the Trustee.

SCE&G is also subject to a bond indenture dated April 1, 1993 (New Mortgage) covering substantially all of its electric properties under which its future mortgage-backed debt (New Bonds) will be issued. New Bonds are issued under the New Mortgage on the basis of a like principal amount of Class A Bonds issued under the Old Mortgage which have been deposited with the Trustee of the New Mortgage. At December 31, 2005, $1.2 billion of Class A Bonds were on deposit with the Trustee of the New Mortgage and are available to support the issuance of additional New Bonds. New Bonds will be issuable under the New 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 (including Class A Bonds) and New Bonds to be outstanding (New Bond Ratio). For the year ended December 31, 2005, the New Bond Ratio was 6.76.

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SCE&G's Restated Articles of Incorporation (the 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 (1.50) times 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, 2005, the Preferred Stock Ratio was 2.12.

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, 2005, the ten percent test would have limited issuances of unsecured indebtedness to approximately $419.5 million. Unsecured indebtedness at December 31, 2005, totaled approximately $246.6 million, and was comprised of short-term borrowings and the interest-free borrowing discussed below.

In 2004 and 2005 SCE&G borrowed an aggregate $59 million available under an agreement with the South Carolina Transportation Infrastructure Bank and the South Carolina Department of Transportation (SCDOT) to fund construction of a roadbed for SCDOT in connection with the Lake Murray Dam remediation project. Such borrowings are being repaid interest-free over ten years from the initial borrowing. At December 31, 2005 SCE&G had $50.2 million outstanding under the agreement.

Public Service Company of North Carolina, Incorporated

PSNC Energy has in effect a medium-term note program for the issuance from time to time of unsecured medium-term debt securities. While issuance of these securities requires regulatory approval, the Indenture under which they would be issued contains no specific limit on the amount which may be issued.

Financing Cash Flows

During 2005 the Company experienced net cash outflows related to financing activities of approximately $131 million primarily due to the reduction of long-term debt and payment of dividends. SCE&G also experienced net cash outflows related to financing activities of approximately $64 million primarily due to the payment of dividends.

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, 2005, the estimated fair value of the Company's swaps totaled $0.1 million (gain) related to combined notional amounts of $47.4 million.

In anticipation of the issuance of debt, the Company uses interest rate lock or similar agreements to manage interest rate risk. These arrangements are designated as cash flow hedges. As such, payments made upon termination of such agreements are amortized to interest expense over the term of the underlying debt. In connection with the issuance of First Mortgage Bonds in May 2003, SCE&G paid

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$11.9 million upon the termination of a treasury lock agreement. In connection with the issuance of First Mortgage Bonds in December 2003, SCE&G paid $3.5 million upon the termination of a forward starting interest rate swap.

In December 2005, SCE&G entered into a $125 million treasury lock agreement at an initial interest rate of 4.72% which will terminate by August 31, 2006. As of December 31, 2005, an unrealized loss on this treasury lock agreement in the amount of approximately $3.8 million has been recorded within other regulatory assets. Any gain or loss on the ultimate settlement of this swap will be amortized over the life of the debt to which it relates.

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

On February 16, 2006, SCANA increased the quarterly cash dividend rate on SCANA common stock to $.42 per share, an increase of 7.7%. The new dividend is payable April 1, 2006 to stockholders of record on March 10, 2006.

ENVIRONMENTAL MATTERS

Capital Expenditures

For the three years ended December 31, 2005, the Company's capital expenditures for environmental control totaled $200.2 million. These expenditures were in addition to expenditures included in "Other operation and maintenance" expenses, which were $25.2 million, $21.5 million, and $29.2 million during 2005, 2004 and 2003, respectively. It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for the Company are $66.9 million for 2006 and $314.3 million for the four-year period 2007 through 2010. These expenditures are included in the Company's construction program, discussed in Liquidity and Capital Resources, and include the matters discussed below.

Electric Operations

In March 2005, the 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 will be installing additional air quality controls to meet the CAIR requirements. Installation and operation and maintenance costs are currently being determined. Such costs are likely to 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. The Company is negotiating with the South Carolina Department of Health and Environmental Control the terms of the state compliance proposals. Installation of additional air quality controls is likely to be required to comply with the mercury rule's emission caps. Compliance plans and costs to comply with the rule will be determined once the Company completes its review and assessments. Such costs are likely to be material and are expected to be recoverable through rates.

The EPA has undertaken an aggressive enforcement initiative against the utilities industry, and the 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 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

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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 new 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, SCE&G's or GENCO'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 $331 million over the 2006-2009 period to install this new equipment. SCE&G and GENCO expect to have increased operation and maintenance costs of approximately $4 million in 2009 and $27 million in 2010 and subsequent years. To meet compliance requirements for the years 2011 through 2015, the Company anticipates additional capital expenditures totaling approximately $564 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.

SCE&G has been named, along with 27 others, by the EPA as a potentially responsible party (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 and the purchase of new transformers. In 1984, EPA initiated a cleanup of PCB-contaminated soil and groundwater at the site. EPA reports that it has spent $36 million to date. SCE&G's records indicated that only minimal quantities of used transformers were shipped by it to CTC, and it is not clear if any contained PCB-contaminated oil. Although a basis for the allocation of clean-up costs among the 28 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 arising from this matter is expected to be recoverable through rates.

Nuclear Fuel Disposal

The Nuclear Waste Policy Act of 1982 (the "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 imposes 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 providing for permanent disposal of its spent nuclear fuel in exchange for agreed payments fixed in the Standard Contract at particular amounts.

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 settlement from DOE which requires the payment by DOE of $9 million to the plaintiffs. The payment is to reimburse the plaintiffs for certain costs incurred from January 31, 1998 through July 31, 2005. SCE&G will record its portion ($6 million) of the settlement as a reduction to its fuel costs. As a result, most of the credit will be passed through to its customers through the fuel clause component of its retail electric rates. The settlement also provides that the plaintiffs may submit annual applications 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.

Gas Distribution

The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual

F-24

expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate solely to regulated operations and 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 $17.7 million and $10.5 million at December 31, 2005 and 2004, respectively. 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. The site is currently being remediated for contamination. SCE&G anticipates that the remaining remediation activities will be completed by mid-2006, with certain monitoring and retreatment activities continuing until 2011. As of December 31, 2005, SCE&G has spent $21.5 million to remediate the Calhoun Park site, and expects to spend an additional $0.3 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. Any cost arising from this matter is expected to be recoverable 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 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 2010. As of December 31, 2005, SCE&G has spent $4.5 million related to these three sites, and expects to spend an additional $11.5 million. Any cost arising from this matter is expected to be recoverable 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 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 $7.4 million, which reflects its estimated remaining liability at December 31, 2005. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates are $3.1 million. Management believes that all MGP cleanup costs will be recoverable through gas rates.

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.

See earlier discussion of increase in retail electric and gas base rates during 2005 in Liquidity and Capital Resources.

In February 2005, the Natural Gas Stabilization Act of 2005 (Stabilization Act) became law in South Carolina. The Stabilization Act 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.

Synthetic Fuel

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.

The aggregate investment in these partnerships as of December 31, 2005 is

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$3.9 million, and through December 31, 2005, they have generated and passed through to SCE&G $188.3 million in tax credits. In a January 2005 order, the SCPSC approved SCE&G's request to apply these tax credits, net of partnership losses and other expenses, to offset the construction costs of the Lake Murray Dam project. Under the accounting methodology approved by the SCPSC, 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 income 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 is declining 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.

Depreciation on the Lake Murray Dam remediation 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 ability to utilize 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 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 certain percentage of the credits would be available.

While the benchmark price range for 2005 has been estimated at between $52 and $65 per barrel, the 2005 reference price will not be known until April 2006. However, SCE&G's analysis indicates that the synthetic fuel tax credits recorded in 2005 should not be impacted by the phase-out calculation. During 2006 and subject to continuing review of the estimated benchmark range and reference price of oil, the Company intends to continue to record synthetic fuel tax credits as they are generated and to apply those credits quarterly to allow the recording of accelerated depreciation related to the balance in the dam remediation project account. 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, the price volatility resulting from the disruptions in the oil and gas markets in the third quarter of 2005 raise significant uncertainty as to the continued availability of the credits in 2006 and 2007. The availability of these synthetic fuel tax credits is also subject to coal availability and other operational risks related to the generating plants.

If it is determined 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, 2005, remaining unrecovered costs, based on management's recording of accelerated deprecation and related tax benefits on its assumption that 2005's credits will not be subjected to the phase-out provisions, were $89.2 million.

Finally, Primesouth, Inc., a subsidiary of SCANA, provides management and maintenance services for a non-affiliated synthetic fuel production facility. Should synthetic fuel tax credit availability be curtailed

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under the above phase-out provisions, the level of payment Primesouth receives for these services could be adversely impacted.

Public Service Company of North Carolina, Incorporated

PSNC Energy is subject to the jurisdiction of the North Carolina Utilities Commission (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 U. S. Congress passed the Pipeline Safety Improvement Act of 2002 (the Pipeline Safety Act), directing the U. S. Department of Transportation (DOT) to establish a pipeline 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 are subject to imprecision, PSNC Energy currently estimates the total cost to be $8 million for the initial assessments and any subsequent remediation required through December 2012. Effective November 1, 2004 the NCUC authorized the Company to defer for subsequent rate consideration certain expenses incurred to comply with DOT's pipeline integrity management requirements.

South Carolina Pipeline Corporation

SCPC has approximately 51 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 are subject to imprecision, SCPC currently estimates the total cost to be $10 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 assets and liabilities. Such an event could have a material adverse effect on the results of operations of the Company's Electric Distribution and Gas Distribution segments in the period the write-off would be recorded. It is not expected that cash flows or financial position would be materially affected. 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

F-27

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, 2005, the Company's net investments in fossil/hydro and nuclear generation assets were approximately $2.3 billion and $552 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 marketing 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 each customer since the date of the last reading of their respective 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. As of December 31, 2005 and 2004, accounts receivable included unbilled revenues of $280.9 million and $213.0 million, respectively, compared to total revenues for 2005 and 2004 of $4.8 billion and $3.9 billion, respectively.

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, 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 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. As such, estimation of the provision for bad debts related to this segment 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 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 share of estimated site-specific nuclear decommissioning costs for Summer Station, including the cost of decommissioning plant components not subject to radioactive contamination, totals $357.3 million, stated in 1999 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in the station. The cost estimate is based on a decommissioning study completed in 2000 which has not yet been updated to incorporate the 20-year license extension for Summer Station received in 2004. SCE&G expects to complete a new decommissioning study in 2006. The cost estimate is based on a decommissioning methodology acceptable to the NRC under

F-28

which the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that permits release for unrestricted use.

Under SCE&G's method of funding decommissioning costs, funds collected through rates are invested in insurance policies on the lives of certain Company personnel. Amounts for decommissioning collected through electric rates, insurance proceeds, and interest on proceeds, less expenses, are transferred by SCE&G to an external trust fund. 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," in accounting for its defined benefit pension plan. The Company's plan is fully funded and as such, net pension income is reflected in the financial statements (see Results of Operations). 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 $18.1 million recorded in 2005 reflects the use of a 5.75% discount rate and an assumed 9.25% 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 5.5% in 2005 would have increased the Company's pension income by approximately $0.4 million. Had the assumed long-term rate of return on assets been 9.0%, the Company's pension income for 2005 would have been reduced by approximately $2.1 million.

In determining the appropriate discount rate for 2005, the Company considered the market indices of high-quality long-term fixed income securities and selected the discount rate of 5.75% as being within a reasonable range of interest rates for obligations rated Aa by Moody's as of January 1, 2005. For 2006, the discount rate to be used will be 5.6%, which was derived using a cash flow matching technique which the Company believes is preferable. 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 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' 2005 review of the plan's historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 9.8%, 11.6%, 11.6% and 12.3%, respectively, all of which have been in excess of related broad indices. The 2005 expected long-term rate of return of 9.25% 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 2006, 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," in accounting for its postretirement medical and life insurance benefits. This plan is unfunded, so no

F-29

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 5.75% and recorded a net SFAS 106 cost of $17.0 million for 2005. Had the selected discount rate been 5.50%, the expense for 2005 would have been $0.2 million higher.

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) which result from their acquisition, construction, development and normal operation. Because such obligations relate primarily to the Company's regulated utility operations, adoption of SFAS 143 and FIN 47 had no significant impact on results of operations. As of December 31, 2005, the Company has recorded an ARO of approximately $132 million for nuclear plant decommissioning (as discussed above) and an ARO of approximately $191 million for other conditional obligations related to generation, transmission and distribution properties, including gas pipelines, which was recorded under FIN 47. 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, but as stated above, these changes in estimates are not expected to materially impact results of operations so long as the regulatory framework for the Company's regulated utilities remains in place.

OTHER MATTERS

Off-Balance Sheet Financing

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, "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 provide information about long-term debt issued by the Company and other financial instruments that are sensitive to changes in interest rates. For debt obligations, the tables present principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the figures shown reflect notional amounts and related maturities. Fair values for debt and swaps represent quoted market prices.

	Expected Maturity Date
December 31, 2005 Millions of dollars Liabilities	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

	Expected Maturity Date
December 31, 2004 Millions of dollars Liabilities	2005	2006	2007	2008	2009	Thereafter	Total	Fair Value
Long-Term Debt:
Fixed Rate ($)	193.6	174.4	68.6	158.6	143.6	2,532.8	3,271.6	3,404.5
Average Fixed Interest Rate (%)	7.39	8.50	6.96	8.12	8.21	6.24	6.62
Variable Rate ($)		200.0					200.0	200.0
Average Variable Interest Rate (%)		2.73					2.73
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)	3.2	3.2	28.2	118.2	3.2	119.6	275.6	4.2
Average Pay Interest Rate (%)	5.74	5.74	6.04	4.73	5.74	4.46	4.78
Average Receive Interest Rate (%)	8.75	8.75	7.11	5.89	8.75	6.45	6.36

While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur.

The above table excludes approximately $97 million and $94 million in long-term debt as of December 31, 2005 and 2004, respectively, which amounts do not have a stated interest rate associated with them.

In December 2005, the Company entered into a $125 million treasury lock agreement at an initial interest rate of 4.72% which will terminate by August 31, 2006. As of December 31, 2005, the fair value of this treasury lock agreement was a loss of approximately $3.8 million.

Commodity price risk — The following table provides information about the Company's financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 mmbtu. Fair value represents quoted market prices.

F-31

				Options
	Futures Contracts			Options
Millions of dollars, except weighted average prices	Futures Contracts			Purchased Call (Long)($)	Purchased Put (Short)($)	Sold Put (Long)($)
Millions of dollars, except weighted average prices	Long($)	Short($)		Purchased Call (Long)($)	Purchased Put (Short)($)	Sold Put (Long)($)
2006
Settlement Price^(a)	11.07	11.21	Strike Price^(a)	9.65	—	7.13
Contract Amount	22.7	8.2	Contract Amount	1.0	—	1.0
Fair Value	23.7	9.0	Fair Value	—	—	—
2007
Settlement Price^(a)	11.61	—	Strike Price^(a)	—	—	—
Contract Amount	1.0	—	Contract Amount	—	—	—
Fair Value	1.0	—	Fair Value	—	—	—

Swaps	2006	2007
Commodity Swaps:
Pay fixed/receive variable ($)	85.3	8.4
Average pay rate^(a)	11.254	8.955
Average received rate^(a)	11.061	10.504
Pay variable/receive fixed ($)	9.2	—
Average pay rate^(a)	11.253	—
Average received rate^(a)	8.665	—
Basis Swaps:
Pay variable/receive variable ($)	137.5	—
Average pay rate^(a)	10.681	—
Average received rate^(a)	10.660	—

^(a): Weighted average

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, SCPC and PSNC Energy. Certain derivatives that SCPC utilizes to hedge its gas purchasing activities are recoverable through its weighted average cost of gas calculation. SCPC's tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. In a July 2005 order, in connection with SCPC's 2005 annual prudency review, the SCPSC determined that SCPC's gas costs, including all hedging activities, were reasonable and prudently incurred during the 12-month review period ended December 31, 2004.

PSNC Energy utilizes NYMEX 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 transaction fees and any realized and unrealized gains or losses from derivatives acquired as part of its hedging program in deferred accounts as a regulatory asset or liability for the over- or under-recovery of gas costs. In a September 2005 order, in connection with PSNC Energy's 2005 annual prudency review, the NCUC determined that PSNC Energy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12-month review period ended March 31, 2005.

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, 2005 and 2004, 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, 2005. 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report (not included herein) dated March 1, 2006, 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
March 1, 2006

F-33

SCANA Corporation
CONSOLIDATED BALANCE SHEETS

			December 31,
			2005			2004
			(Millions of dollars)
Assets
Utility Plant In Service			$	8,999		$	8,373
Accumulated Depreciation and Amortization				(2,698	)		(2,315	)

				6,301			6,058
Construction Work in Progress				175			432
Nuclear Fuel, Net of Accumulated Amortization				28			42
Acquisition Adjustments				230			230

Utility Plant, Net				6,734			6,762

Nonutility Property and Investments:
	Nonutility property, net of accumulated depreciation of $62 and $50			108			104
	Assets held in trust, net — nuclear decommissioning			52			49
	Other investments			87			83

	Nonutility Property and Investments, Net			247			236

Current Assets:
	Cash and cash equivalents			62			119
	Receivables, net of allowance for uncollectible accounts of $25 and $16			881			712
	Receivables — affiliated companies			24			19
	Inventories (at average cost):
		Fuel		284			191
		Materials and supplies		79			70
		Emission allowances		54			9
	Prepayments and other			54			52
	Deferred income taxes			26			10

	Total Current Assets			1,464			1,182

Deferred Debits:
	Environmental			28			18
	Pension asset, net			303			285
	Other regulatory assets			589			372
	Other			154			151

	Total Deferred Debits			1,074			826

		Total	$	9,519		$	9,006

F-34

			December 31,
			2005		2004
			(Millions of dollars)
Capitalization and Liabilities
Shareholders' Investment:
	Common equity		$	2,677	$	2,451
	Preferred stock (Not subject to purchase or sinking funds)			106		106

	Total Shareholders' Investment			2,783		2,557
Preferred Stock, Net (Subject to purchase or sinking funds)				8		9
Long-Term Debt, Net				2,948		3,186

	Total Capitalization			5,739		5,752

Current Liabilities:
	Short-term borrowings			427		211
	Current portion of long-term debt			188		204
	Accounts payable			471		381
	Accounts payable — affiliated companies			26		18
	Customer deposits and customer prepayments			70		66
	Taxes accrued			112		132
	Interest accrued			52		51
	Dividends declared			47		43
	Other			107		78

	Total Current Liabilities			1,500		1,184

Deferred Credits:
	Deferred income taxes, net			940		895
	Deferred investment tax credits			121		121
	Asset retirement obligations			322		124
	Non-legal asset retirement obligations			488		450
	Postretirement benefits			148		142
	Other regulatory liabilities			117		209
	Other			144		129

	Total Deferred Credits			2,280		2,070

Commitments and Contingencies (Note 10)				—		—

		Total	$	9,519	$	9,006

See Notes to Consolidated Financial Statements.

F-35

SCANA Corporation
CONSOLIDATED STATEMENTS OF INCOME

		For the Years Ended December 31,
		2005			2004			2003
		(Millions of dollars, except per share amounts)
Operating Revenues:
	Electric	$	1,909		$	1,688		$	1,466
	Gas — regulated		1,405			1,126			1,086
	Gas — nonregulated		1,463			1,071			864

	Total Operating Revenues		4,777			3,885			3,416

Operating Expenses:
	Fuel used in electric generation		618			467			334
	Purchased power		37			51			64
	Gas purchased for resale		2,399			1,753			1,532
	Other operation and maintenance		632			608			558
	Depreciation and amortization		510			265			238
	Other taxes		145			145			139

	Total Operating Expenses		4,341			3,289			2,865

Operating Income			436			596			551

Other Income (Expense):
	Other revenues		248			181			167
	Other expenses		(200	)		(160	)		(123	)
	Gain (loss) on sale of investments and assets		9			(20	)		61
	Investment impairments		—			(27	)		(53	)
	Preferred dividends of subsidiary		(7	)		(7	)		(9	)
	Allowance for equity funds used during construction		—			16			19
	Interest charges, net of allowance for borrowed funds used during construction of $3, $10 and $11		(212	)		(202	)		(200	)

	Total Other Expense		(162	)		(219	)		(138	)

Income Before Income Taxes (Benefit) and Earnings (Losses) from Equity Method Investments			274			377			413
Income Tax Expense (Benefit)			(118	)		123			135

Income Before Earnings (Losses) from Equity Method Investments			392			254			278
Earnings (Losses) from Equity Method Investments			(72	)		3			4

Net Income		$	320		$	257		$	282

Basic and Diluted Earnings Per Share of Common Stock		$	2.81		$	2.30		$	2.54
Weighted Average Common Shares Outstanding (Millions)			113.8			111.6			110.8

See Notes to Consolidated Financial Statements.

F-36

SCANA Corporation
CONSOLIDATED STATEMENTS OF CASH FLOWS

			For the Years Ended December 31,
			2005			2004			2003
			(Millions of dollars)
Cash Flows From Operating Activities:
Net Income			$	320		$	257		$	282
Adjustments to Reconcile Net Income to Net Cash Provided From Operating Activities:
	Losses (earnings) from equity method investments			72			(3	)		(4	)
	Depreciation and amortization			518			274			249
	Amortization of nuclear fuel			18			22			21
	(Gain) loss on sale of assets and investments			(9	)		20			(61	)
	Impairment of investments			—			27			53
	Hedging activities			4			11			4
	Allowance for equity funds used during construction			—			(16	)		(19	)
	Carrying cost recovery			(11	)		—			—
	Cash provided (used) by changes in certain assets and liabilities:
		Receivables, net		(174	)		(225	)		(60	)
		Inventories		(188	)		(90	)		(8	)
		Prepayments and other		—			(2	)		4
		Pension asset		(17	)		(14	)		(5	)
		Other regulatory assets		(28	)		(17	)		—
		Deferred income taxes, net		25			74			38
		Regulatory liabilities		(159	)		48			53
		Postretirement benefits obligations		6			7			4
		Accounts payable		79			91			(69	)
		Taxes accrued		(20	)		23			6
		Interest accrued		1			(4	)		3
	Changes in fuel adjustment clauses			(7	)		(3	)		23
	Changes in other assets			(17	)		22			(6	)
	Changes in other liabilities			54			77			37

Net Cash Provided From Operating Activities				467			579			545

Cash Flows From Investing Activities:
	Utility property additions and construction expenditures			(366	)		(478	)		(668	)
	Proceeds from sale of assets and investments			10			68			74
	Nonutility property additions			(19	)		(23	)		(12	)
	Investments			(18	)		(20	)		(22	)

Net Cash Used For Investing Activities				(393	)		(453	)		(628	)

Cash Flows From Financing Activities:
	Proceeds from issuance of common stock			84			65			6
	Proceeds from issuance of debt			221			136			978
	Repayments of debt			(470	)		(169	)		(856	)
	Redemption/repurchase of equity securities			(1	)		(4	)		(61	)
	Dividends on equity securities			(181	)		(168	)		(158	)
	Short-term borrowings, net			216			16			(14	)

Net Cash Used For Financing Activities				(131	)		(124	)		(105	)

Net Increase (Decrease) in Cash and Cash Equivalents				(57	)		2			(188	)
Cash and Cash Equivalents, January 1				119			117			305

Cash and Cash Equivalents, December 31			$	62		$	119		$	117

Supplemental Cash Flow Information:
	Cash paid for — Interest (net of capitalized interest of $3, $10 and $11)		$	213		$	206		$	197
	— Income taxes			58			24			77
Noncash Investing and Financing Activities:
	Unrealized gain (loss) on securities available for sale, net of tax			—			(2	)		2
	Accrued construction expenditures			36			49			34

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 January 1, 2003		111	$	1,192		$	984		$	1		$	2,177
Comprehensive Income:
	Net Income						282						282
	Unrealized gains on securities, net of taxes $1									2			2
	Unrealized gains on hedging activities, net of taxes $2									3			3

	Total Comprehensive Income						282			5			287
Issuance of Common Stock				6									6
Repurchase of Common Stock				(11	)								(11	)
Dividends Declared on Common Stock							(153	)					(153	)

Balance as of December 31, 2003		111	$	1,187		$	1,113		$	6		$	2,306

Comprehensive Income (Loss):
	Net Income						257						257
	Unrealized loss on securities, net of taxes $(1)									(2	)		(2	)
	Unrealized loss on hedging activities, net of taxes $(4)									(8	)		(8	)

	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
	Unrealized gains on hedging activities, net of taxes $1									1			1
	Minimum pension liability adjustment, net of taxes $(1)									(1	)		(1	)

	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

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, through wholly owned subsidiaries, is engaged 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 is also engaged in 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)
South Carolina Pipeline Corporation (SCPC)
SCG Pipeline, Inc.

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.

Certain investments are reported 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 as of December 31, 2005, approximately $617 million and $605 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.

	December 31,
Millions of dollars	2005			2004
Accumulated deferred income taxes, net	$	138		$	126
Under-collections — electric fuel and gas cost adjustment clauses, net		41			9
Deferred purchased power costs		17			26
Deferred environmental remediation costs		28			18
Asset retirement obligations and related funding		250			76
Non-legal asset retirement obligations		(488	)		(450	)
Deferred synthetic fuel tax benefits, net		—			(97	)
Storm damage reserve		(38	)		(33	)
Franchise agreements		56			58
Deferred regional transmission organization costs		11			14
Other		(3	)		(16	)

Total	$	12		$	(269	)

Accumulated deferred income tax liabilities arising from utility operations that have not been

F-39

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-collections — electric fuel and gas cost adjustment clauses, net, represent amounts under-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. See Note 1F.

Deferred purchased power costs represents costs that were 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.

Deferred 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 $17.7 million remain to be recovered. A portion of the costs incurred at sites owned by PSNC Energy has been recovered through rates. Amounts incurred and deferred, net of insurance settlements, that are not currently being recovered by PSNC Energy through rates are approximately $3.1 million. Management believes that these costs and the estimated remaining costs of approximately $7.4 million will be recoverable by PSNC Energy.

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."

Non-legal AROs represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets.

Deferred synthetic fuel tax benefits, net represented the deferral of partnership losses and other expenses offset by the tax benefits of those losses and expenses and accumulated synthetic fuel tax credits associated with SCE&G's investment in two partnerships involved in converting coal to synthetic fuel. In 2005, under an accounting plan approved by the SCPSC, any tax credits generated from synthetic fuel produced by the partnerships and consumed by SCE&G and ultimately passed through to SCE&G, net of partnership losses and other expenses, are being used to offset the capital costs of constructing the back-up dam at Lake Murray. See Note 2.

The storm damage reserve represents an SCPSC approved reserve account for SCE&G capped at $50 million to be collected through rates. The accumulated storm damage reserve can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. During the year ended December 31, 2005, no significant amounts were drawn from this reserve account. During the year ended December 31, 2004, approximately $10.9 million was drawn from this reserve account.

Franchise agreements represent costs associated with the 30-year electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. These amounts are being amortized through cost of service rates over approximately 15 years.

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Deferred 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 over approximately five years.

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. System of Accounts

The accounting records of the Company's regulated subsidiaries are maintained in accordance with the Uniform System of Accounts prescribed by FERC and as adopted by state commissions.

D. 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) are joint owners of 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, 2005 and 2004 (including amounts related to ARO). Accumulated depreciation associated with SCE&G's share of Summer Station was $478.7 million and $463.7 million as of December 31, 2005 and 2004, 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 $76.3 million, $74.5 million and $74.7 million for the years ended December 31, 2005, 2004 and 2003, respectively.

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 allowed to collect $8.5 million annually over an eight-year period through electric rates to offset turbine

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maintenance expenditures. For the year ended December 31, 2005, SCE&G incurred $4.9 million for turbine maintenance. The remaining $3.6 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 $0.8 million per month from January 2004 through June 2005 for its portion of the outage in April 2005 and is accruing $1.0 million per month for its portion of the outage scheduled for October 2006. Total costs for the 2005 outage were $22.3 million, of which SCE&G was responsible for $14.9 million. Total costs for the planned outage in 2006 are estimated to be $25.7 million, of which SCE&G will be responsible for $17.2 million. As of December 31, 2005 and 2004, SCE&G had accrued $5.7 million and $9.9 million, respectively.

E. 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 4.9%, 6.9% and 8.1% for 2005, 2004 and 2003, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. Interest on nuclear fuel in process is capitalized at the actual interest amount incurred.

F. Revenue Recognition

Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered, but not yet billed. Unbilled revenues totaled $280.9 million and $213.0 million as of December 31, 2005 and 2004, respectively.

Fuel costs for electric generation are collected through the fuel cost component in retail electric rates. The fuel cost component contained in electric rates 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 fuel cost hearing. SCE&G had undercollected through the electric fuel cost component $44.1 million and $6.0 million at December 31, 2005 and 2004, 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 gas cost recovery hearing. At December 31, 2005 and 2004, SCE&G had undercollected $11.8 million and overcollected $7.8 million, respectively, which amounts are also included in other regulatory assets or liabilities. At December 31, 2005, PSNC Energy had overcollected $15.1 million, net, which also is included in other regulatory liabilities. At December 31, 2004, PSNC Energy had undercollected $10.8 million, net, which is included in other regulatory assets.

SCE&G's and PSNC Energy's gas rate schedules for residential, small commercial and small industrial customers include a weather

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normalization adjustment which minimizes fluctuations in gas revenues due to abnormal weather conditions.

G. Depreciation and Amortization

Provisions for depreciation and amortization are recorded using the straight-line method and are 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:

	2005		2004		2003
SCE&G	3.20	%	2.99	%	3.02	%
GENCO	2.66	%	2.66	%	2.66	%
SCPC	2.01	%	2.04	%	2.13	%
PSNC Energy	3.77	%	3.87	%	4.05	%
Aggregate of Above	3.20	%	3.04	%	3.10	%

For SCE&G, the above rates reflect higher depreciation rates approved by the SCPSC in connection with electric and gas rate cases effective January 2005 and November 2005, respectively. See Note 2.

Nuclear fuel amortization, which is included in "Fuel used in electric generation" and recovered through the fuel cost component of SCE&G's rates, is recorded using the units-of-production method. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the 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 on the books of PSNC Energy (Gas Distribution segment) and approximately $40 million ($20 million net of accumulated amortization) recorded on the books of SCPC (Gas Transmission segment). In accordance with SFAS 142, the Company performs an annual impairment evaluation of its investment in PSNC Energy and SCPC. These calculations have indicated no need for write-downs of acquisition adjustments since the write-down taken by PSNC Energy upon initial adoption of SFAS 142 in 2002. Should a write-down be required in the future, such a charge would be treated as an operating expense.

H. 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 not subject to radioactive contamination, totals $357.3 million, stated in 1999 dollars, based on a decommissioning study completed in 2000. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station. The cost estimate is based on a decommissioning methodology acceptable to the Nuclear Regulatory Commission (NRC) under which the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that permits release for unrestricted use.

Under SCE&G's method of funding decommissioning costs, amounts collected through rates ($3.2 million in each of 2005, 2004 and 2003) are invested in insurance policies on the lives of certain Company personnel. Amounts collected through electric rates, insurance proceeds, and interest on proceeds, less expenses, are transferred by SCE&G to an external trust fund. The trusteed asset balance reflects the net cash surrender value of the insurance policies held by the trust. Management intends for the fund, including

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earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.

I. 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 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.

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

Long-term debt premium and discount are recorded in long-term debt and are amortized 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.

K. Environmental

The Company maintains an environmental assessment program to identify and evaluate current and former sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and clean up 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 cleanup relate solely to regulated operations.

L. 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.

M. 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.

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utilizes to hedge its gas purchasing activities are recoverable through its 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 transaction fees and any realized and unrealized gains or losses from derivatives acquired as part of its hedging program in deferred accounts as a regulatory asset or liability for the over or under recovery of gas costs.

N. New Accounting Standards

SFAS 154, "Accounting Changes and Error Corrections," was issued in June 2005. It 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 Accounting Principles Board (APB) Opinion 20, "Accounting Changes," and SFAS 3, "Reporting Accounting Changes in Interim Financial Statements," although it carries forward some of their provisions. The Company will adopt SFAS 154 in the first quarter of 2006, 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.

Effective December 15, 2005, the Company adopted FIN 47, which was issued to clarify the term "conditional asset retirement" as used in SFAS 143. It requires that a liability be recognized for the fair value of a conditional asset retirement obligation when incurred if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.

The following table presents conditional asset retirement obligations and related assets as recorded in the Consolidated Balance Sheet as of December 31, 2005, and the proforma amounts that would have been recorded as of December 31, 2004 and 2003 had FIN 47 been adopted at the beginning of 2003.

Millions of dollars	December 31, 2005 Actual			December 31, 2004 Proforma			December 31, 2003 Proforma
Assets:
Within utility plant	$	45		$	45		$	45
Within accumulated depreciation		(23	)		(22	)		(21	)
Within other regulatory assets		169			159			149

Total	$	191		$	182		$	173

Liabilities:
Within asset retirement obligations	$	191		$	182		$	173

Due to the regulated nature of the business for which conditional asset retirement obligations were recognized, the adoption of FIN 47 did not have a material impact on the Company's results of operations, cash flows or financial position for the year ended December 31, 2005. Proforma net income and earnings per share for the periods prior to the adoption of FIN 47 would not differ from amounts actually recorded during these periods. A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations is as follows:

Millions of dollars	2005		2004
Beginning balance	$	124	$	117
Accretion expense		7		7
Adoption of FIN 47		191		—

Ending Balance	$	322	$	124

SFAS 123 (revised 2004), "Share-Based Payment," was issued in December 2004 and will require compensation costs related to share-

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based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the instruments issued. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) replaces SFAS 123, "Accounting for Stock-Based Compensation" and supersedes APB 25, "Accounting for Stock Issued to Employees." The Company plans to adopt SFAS 123(R) in the first quarter of 2006 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.

O. Equity Compensation Plan

Under the SCANA Corporation Long-Term Equity Compensation Plan, certain employees and non-employee directors may receive incentive and nonqualified stock options and other forms of equity-based compensation. The Company accounts for this equity-based compensation using the intrinsic value method under APB 25, "Accounting for Stock Issued to Employees, "and related interpretations. In addition, the Company has adopted the disclosure provisions of SFAS 123, "Accounting for Stock-Based Compensation," and SFAS 148, "Accounting for Stock-Based Compensation-Transition and Disclosure."

Options, all of which were granted prior to 2005, and all of which were fully vested as of December 31, 2005, 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 has been 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, pro forma net income and earnings per share would have been as follows:

	2005		2004		2003
Net income — as reported (millions)	$	319.5	$	257.1	$	282.0
Net income — pro forma (millions)		319.3		256.0		280.3
Basic and diluted earnings per share — as reported	$	2.81	$	2.30	$	2.54
Basic and diluted earnings per share — pro forma		2.80		2.29		2.52

The Company also grants other forms of equity-based compensation (performance awards) to certain employees. The value of such awards is recognized as compensation expense under APB 25.

P. 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.

Q. Transactions with Affiliates

The Company received cash distributions from equity investees of approximately $7.1 million, $7.3 million and $7.4 million during 2005, 2004 and 2003, respectively.

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SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel. SCE&G's receivables from these affiliated companies were $24.6 million and $18.6 million at December 31, 2005 and 2004, respectively. SCE&G's payables to these affiliated companies were $25.3 million and $17.8 million at December 31, 2005 and 2004, respectively. SCE&G purchased approximately $248.1 million, $190.6 million and $145.8 million of synthetic fuel from these affiliated companies in 2005, 2004 and 2003, respectively.

Summarized combined financial information of unconsolidated affiliates as of and for the years ended December 31, 2005, 2004 and 2003, is presented below:

Millions of dollars	2005			2004			2003
Current assets	$	61		$	55		$	52
Non-current assets		339			355			371
Current liabilities		56			49			47
Non-current liabilities		186			200			213
Revenues		333			314			271
Gross profit		52			31			35
Loss before income taxes		(33	)		(34	)		(23	)

R. Reclassifications

Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2005.

S. 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

South Carolina Electric & Gas Company

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 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 approximately $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 deferred under a previous order. 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

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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, but may not be carried forward indefinitely. No such additional depreciation was recognized in 2005, 2004 or 2003.

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 2005 and 2004 was as follows:

Rate Per KWh		Effective Date
$.01678		January-April 2004
$.01821		May-December 2004
$.01764		January-April 2005
$.02256		May-December 2005

Gas

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 component in effect during 2005 and 2004 was as follows:

Rate Per Therm		Effective Date
$.877		January-October 2004
$.903		November 2004-October 2005

In October 2005 the SCPSC approved an increase in SCE&G's cost of gas component from a rate of $.903 per therm for all customer classes to rates of $1.29729, $1.22218 and $1.19823 per therm for residential, small and medium general service and large general service classes, respectively. These new rates were effective with the first billing cycle in November 2005. As a part of this proceeding, in order to moderate the effect of volatile natural gas prices on customers, the SCPSC approved a plan to defer certain under-collections of gas costs until November 2006. Effective in December 2005, the SCPSC approved an increase in the cost of gas component to $1.36159, $1.28648 and $1.26253 per therm for residential, small and medium general service and large general service classes, respectively.

Since January 1, 2006, the SCPSC has approved decreases in SCE&G's cost of gas components from $1.36159, $1.28648 and $1.26253 to $1.22695, $1.15184 and $1.12789 per therm for residential, small and medium general service and large general service classes, respectively, effective February 14, 2006.

Prior to November 2005, the SCPSC allowed SCE&G to recover through a billing surcharge to its gas customers the costs of environmental cleanup 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 will defer certain MGP environmental costs in regulatory asset accounts and collect and amortize these costs through base rates.

Public Service Company of North Carolina, Incorporated

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.

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PSNC Energy's benchmark cost of gas in effect during 2005 and 2004 was as follows:

Rate Per Therm		Effective Date
$.600		January-September 2004
$.675		October-November 2004
$.825		December 2004-January 2005
$.725		February-July 2005
$.825		August-September 2005
$1.10		October 2005
$1.275		November-December 2005

Since January 1, 2006 the NCUC has approved decreases in PSNC Energy's benchmark cost of gas to $.825 per therm for service rendered on and after March 1, 2006.

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.

In September 2005, in connection with the Company's 2005 Annual Prudence Review, the NCUC determined that PSNC Energy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12-month review period ended March 31, 2005. The NCUC also authorized new rate decrements, effective October 1, 2005, to refund over-collections of certain gas costs included in deferred accounts.

A state expansion fund, established by the North Carolina General Assembly and funded by refunds from PSNC Energy's interstate pipeline transporters, provides financing for expansion into areas that otherwise would not be economically feasible to serve. In September 2005 the NCUC approved PSNC Energy's request for disbursement of up to $1.1 million from the expansion fund to extend natural gas service to Louisburg, North Carolina. The project is expected to be completed in 2006.

In March 2005 PSNC Energy refunded approximately $7.7 million in pipeline supplier refunds by a direct bill credit to various customers.

Effective November 1, 2004 the NCUC authorized PSNC Energy to defer for subsequent rate consideration certain expenses incurred to comply with the U. S. Department of Transportation's Pipeline Integrity Management requirements.

South Carolina Pipeline Corporation

SCPC's purchased gas adjustment for cost recovery and gas purchasing policies are reviewed annually by the SCPSC. In a July 2005 order, the SCPSC found that for the period January through December 2004 SCPC's gas purchasing policies and practices were prudent and SCPC properly adhered to the gas cost recovery provisions of its gas tariff.

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 who elected that option and for all new employees. 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,

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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.

The measurement date used to determine pension and other postretirement benefit obligations is December 31.

Changes in Benefit Obligation

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	2005			2004			2005			2004
Benefit obligation, January 1	$	669.5		$	619.9		$	197.5		$	188.4
Service cost		12.2			11.1			3.5			3.3
Interest cost		38.3			37.4			10.7			11.4
Plan participants' contributions		—			—			2.3			1.1
Plan amendments		—			8.0			(0.3	)		4.7
Actuarial loss		27.1			24.1			1.5			1.2
Benefits paid		(35.6	)		(31.0	)		(13.1	)		(12.6	)

Benefit obligation, December 31	$	711.5		$	669.5		$	202.1		$	197.5

The accumulated benefit obligation for retirement benefits at the end of 2005 and 2004 was $664.4 million and $635.8 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:

		2005		2004
Annual discount rate used to determine benefit obligations		5.60	%	5.75	%
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 2005. The rate was assumed to decrease gradually to 5.0% for 2012 and to remain at that level thereafter. The effects of a one percentage point increase or decrease on accumulated other postretirement benefit obligation for health care benefits are as follows:

Millions of dollars		1% Increase			1% Decrease
Effect on postretirement benefit obligation		$	3.5		$	(3.1	)

In May 2004, the Financial Accounting Standards Board issued Staff Position 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act" ("FSP 106-2"). FSP 106-2 provides definitive guidance on the recognition of the effects of the Medicare Prescription Drug Improvement and Modernization Act of 2003 and related disclosure requirements for employers that sponsor prescription drug benefit plans for retirees. In the quarter beginning July 1, 2004 the Company adopted FSP 106-2. The expected subsidy reduced the accumulated postretirement benefit obligation (APBO) as of July 1, 2004 by $3.7 million, and net periodic cost for 2004 by $0.2 million, as compared to the amount calculated without considering the effects of the subsidy.

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Changes in Plan Assets

	Retirement Benefits
Millions of dollars	2005			2004
Fair value of plan assets, January 1	$	846.7		$	787.7
Actual return on plan assets		43.2			90.0
Benefits paid		(35.6	)		(31.0	)

Fair value of plan assets, December 31	$	854.3		$	846.7

At the end of 2005 and 2004, the fair value of plan assets for the pension plan exceeded both the projected benefit obligation and the accumulated benefit obligation discussed above. Since the accumulated benefit obligation is less than the fair value of plan assets, there is no adjustment to other comprehensive income.

Funded Status of Plans

	Retirement Benefits				Other Postretirement Benefits
Millions of dollars	2005		2004		2005			2004
Funded status, December 31	$	142.9	$	177.2	$	(202.1	)	$	(197.5	)
Unrecognized actuarial loss		88.4		28.2		44.4			44.2
Unrecognized prior service cost		71.3		78.3		5.2			6.4
Unrecognized net transition obligation		0.6		1.4		4.3			5.0

Net asset (liability) recognized in consolidated balance sheet	$	303.2	$	285.1	$	(148.2	)	$	(141.9	)

In connection with the joint ownership of Summer Station, as of December 31, 2005 and 2004, the Company recorded within deferred credits a $10.2 million and $9.7 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, 2005 and 2004, the Company also recorded within deferred debits a $7.1 million and $6.8 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
2006	$	35.9	$	11.3	$	10.9
2007		37.7		12.1		11.7
2008		39.6		12.8		12.3
2009		41.6		13.2		12.7
2010		43.6		13.7		13.2
2011-2015		253.5		72.8		70.6

*Net of participant contributions

Net Periodic Cost

As allowed by SFAS 87 and SFAS 106, 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" are set forth in the following tables.

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Components of Net Periodic Benefit Cost (Income)

	Retirement Benefits									Other Postretirement Benefits
Millions of dollars	2005			2004			2003			2005		2004		2003
Service cost	$	12.2		$	11.1		$	9.5		$	3.5	$	3.3	$	2.7
Interest cost		38.3			37.4			36.7			10.7		11.4		11.4
Expected return on assets		(76.3	)		(71.0	)		(59.9	)		n/a		n/a		n/a
Prior service cost amortization		6.9			6.6			6.3			0.8		1.4		0.9
Amortization of actuarial (gain) loss		—			—			1.6			1.2		1.9		1.5
Transition amount amortization		0.8			0.8			0.8			0.8		0.8		0.8

Net periodic benefit (income) cost	$	(18.1	)	$	(15.1	)	$	(5.0	)	$	17.0	$	18.8	$	17.3

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

	Retirement Benefits						Other Postretirement Benefits
	2005		2004		2003		2005		2004		2003
Discount rate	5.75	%	6.00	%	6.50	%	5.75	%	6.00	%	6.50	%
Expected return on plan assets	9.25	%	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	%	9.50	%	10.00	%
Ultimate health care cost trend rate	n/a		n/a		n/a		5.00	%	5.00	%	5.00	%
Year achieved	n/a		n/a		n/a		2011		2011		2011
Measurement date	Jan 1		Jan 1		Jan 1		Jan 1		Jan 1		Jan 1

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.

Pension Plan Asset Allocations

The Company's pension plan asset allocation at December 31, 2005 and 2004 and the target allocations for 2006 are as follows:

Asset Category	Target Allocation		Percentage of Plan Assets At December 31,
	2006		2005		2004
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 9.25% 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 2006, the expected rate of return will be 9.0%.

Long-Term Equity Compensation Plan

The Long-Term Equity Compensation Plan provides for grants of incentive and nonqualified stock options, stock appreciation rights, restricted stock, performance shares and

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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.

A summary of activity related to nonqualified stock options follows:

	Number of Options		Weighted Average Exercise Price
Outstanding — January 1, 2003	1,717,910		$	27.39
Exercised	(203,052	)		27.41
Forfeited	(21,173	)		27.50

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	(297,477	)		27.40
Forfeited	—			—

Outstanding — December 31, 2005	432,970			27.53

No options have been granted since 2002, and as of December 31, 2005, all options had vested. The options expire ten years after the grant date. At December 31, 2005, all outstanding options could be exercised at prices ranging from $25.50-$29.60, and had a weighted-average remaining contractual life of 6.1 years.

At December 31, 2004 and 2003 exercisable options totaled 388,487 at a weighted average exercise price of $27.42 and 648,392 at a weighted average exercise price of $27.19, respectively.

The Company also grants other forms of equity based compensation to certain employees. These performance awards consist of hypothetical share grants which vest and become payable upon the attainment of specified performance metrics, and compensation is recorded under APB 25. These awards may be settled in shares of Company stock or in cash at the Company's determination. Total expense recorded for these awards was approximately $3.6 million, $12.9 million and $8.9 million in 2005, 2004 and 2003, respectively.

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	2005			2004
			Millions of dollars
Medium-Term Notes (unsecured)(a)	6.29%	2007-2012	$	940		$	1,040
First Mortgage Bonds (secured)	5.98%	2009-2035		1,550			1,700
First & Refunding Mortgage Bonds (secured)	9.00%	2006		131			131
GENCO Notes (secured)	5.97%	2011-2024		127			130
Industrial and Pollution Control Bonds	5.24%	2012-2032		156			156
Senior Debentures(b)	7.50%	2012-2026		122			126
Fair value of interest rate swaps(c)				25			32
Other		2006-2014		107			94

Total debt				3,158			3,409
Current maturities of long-term debt				(188	)		(204	)
Unamortized Discount				(22	)		(19	)

Total long-term debt, net			$	2,948		$	3,186

(a): In 2005, 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 2005, includes $22.4 million of fixed rate debt hedged by variable interest rate swaps.
(c): In 2005, includes $24.7 million representing unamortized payments received to terminate previous swaps. See discussion at Note 9.

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The annual amounts of long-term debt maturities and sinking fund requirements for the years 2006 through 2010 are summarized as follows:

Year	Millions of dollars
2006	$	188
2007		78
2008		267
2009		183
2010		50

Approximately $35.5 million of the long-term debt maturing in 2006 relates to a sinking fund requirement, which may be satisfied by either deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits, or by deposit of cash with the Trustee.

Substantially all of SCE&G's and GENCO's 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 and short-term borrowings at December 31, 2005 and 2004, are as follows:

Millions of dollars			2005			2004
Lines of credit (total and unused)
	Committed
		Short-term	$	350		$	100
		Long-term		650			650
	Uncommitted			103^(a)			113^(a)
Bank loans/commercial paper outstanding (270 or fewer days):
	SCANA		$	25			—
		Weighted average interest rate		4.43	%		—
	SCE&G		$	196		$	122
		Weighted average interest rate		4.40	%		2.39	%
	Fuel Company		$	107		$	31
		Weighted average interest rate		4.39	%		2.44	%
	PSNC Energy		$	99		$	58
		Weighted average interest rate		4.47	%		2.47	%
	Total		$	427		$	211
		Weighted average interest rate		4.42	%		2.42	%

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

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

Nuclear and fossil fuel inventories and sulfur dioxide 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 June 30, 2010.

6. COMMON EQUITY

The Company'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

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dividends on its common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2005 approximately $51 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 2005, 2004 and 2003 at an annual rate per share of $1.56, $1.46 and $1.38, 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			Accumulated Other Comprehensive Income (loss)
Balance, January 1, 2003			—		$	1			—		$	1
	Other comprehensive income	$	2			3			—			5

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	)

During 2005, no unrealized gains (losses) on securities were reclassified into net income. The Company recognized a gain of $4.0 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the year ended December 31, 2005. The Company also recorded a minimum pension liability during the year ended December 31, 2005.

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. (ITC^DeltaCom) and the impairment and subsequent sale of the Company's investment in Knology, Inc. (Knology). See Note 9. 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.

During 2003, no unrealized gains (losses) on securities were reclassified into net income. The Company recognized a gain of $3.9 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the year ended December 31, 2003.

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 2006 through 2010 is $2.6 million. The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend. At December 31, 2005 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	601,613	300,000
$ 25	2,000,000	2,000,000

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Preferred Stock (Not subject to purchase or sinking funds)

For each of the three years ended December 31, 2005 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 2005, 2004 and 2003 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 January 1, 2003			83,849			116,124		199,973		$	10.0
	Shares Redeemed — $50 par value		(2,815	)		(3,563	)	(6,378	)		(0.3	)

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

8. INCOME TAXES

Total income tax expense (benefit) attributable to income for 2005, 2004 and 2003 is as follows:

Millions of dollars			2005			2004			2003
Current taxes:
	Federal		$	10.2		$	(6.4	)	$	63.1
	State			11.1			(5.2	)		12.2

		Total current taxes		21.3		$	(11.6	)	$	75.3

Deferred taxes, net:
	Federal			1.7			84.5			24.6
	State			(6.9	)		5.4			0.3

		Total deferred taxes		(5.2	)		89.9			24.9

Investment tax credits:
	Deferred — state			5.1			10.0			5.0
	Amortization of amounts deferred — state			(1.9	)		(2.1	)		(1.8	)
	Amortization of amounts deferred — federal			(3.1	)		(4.0	)		(4.0	)

		Total investment tax credits		0.1			3.9			(0.8	)

Synthetic fuel tax credits — federal				(134.2	)		40.5			35.7

	Total income tax expense (benefit)		$	(118.0	)	$	122.7		$	135.1

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 is reconciled as follows:

Millions of dollars			2005			2004			2003
Income			$	319.5		$	257.1		$	282.0
Income tax expense (benefit)				(118.0	)		122.7			135.1
Preferred stock dividends				7.3			7.3			9.1

		Total pre-tax income	$	208.8		$	387.1		$	426.2

Income taxes on above at statutory federal income tax rate			$	73.1		$	135.5		$	149.2
Increases (decreases) attributed to:
	State income taxes (less federal income tax effect)			4.8			5.3			10.2
	Synthetic fuel tax credits			(181.9	)		(2.9	)		(2.2	)
	Allowance for equity funds used during construction			(0.2	)		(5.5	)		(6.7	)
	Deductible dividends — Stock Purchase Savings Plan			(5.9	)		(5.5	)		(4.9	)
	Amortization of federal investment tax credits			(3.1	)		(4.0	)		(4.0	)
	Non-taxable recovery of Lake Murray Dam project carrying costs			(3.8	)		—			—
	Other differences, net			(1.0	)		(0.2	)		(6.5	)

		Total income tax expense (benefit)	$	(118.0	)	$	122.7		$	135.1

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The tax effects of significant temporary differences comprising the Company's net deferred tax liabilities are as follows:

			December 31,
Millions of dollars			2005		2004
Deferred tax assets:
	Nondeductible reserves		$	84.8	$	84.5
	Unamortized investment tax credits			60.0		60.8
	Federal alternative minimum tax credit carryforward			44.0		12.3
	Deferred compensation			28.5		24.0
	Unbilled revenue			12.6		7.0
	Other			31.6		28.4

		Total deferred tax assets		261.5		217.0

Deferred tax liabilities:
	Property, plant and equipment			971.7		937.9
	Pension plan benefit income			109.9		101.4
	Deferred fuel costs			45.1		20.3
	Other			49.3		41.9

		Total deferred tax liabilities		1,176.0		1,101.5

Net deferred tax liability			$	914.5	$	884.5

Previously, the Internal Revenue Service had completed and closed examinations of the Company's consolidated federal income tax returns through tax years ending in 2000. In 2005, the Company filed amended federal income tax returns for 1998-2003 which are currently under examination. The Company does not anticipate that any adjustments which might result from these examinations will have a significant impact on the earnings, cash flows or financial position of the Company. The IRS has also closed the examination of S. C. Coaltech No. 1 L.P., a synthetic fuel partnership in which the Company has an interest, for the 2000 tax year, resulting in that return being accepted as filed. The Company continues to believe that all of its synthetic fuel tax credits have been properly claimed. As discussed in Note 1, certain synthetic fuel tax credits were deferred until 2005, at which time they began to be recognized for financial reporting purposes.

9. FINANCIAL INSTRUMENTS

Financial instruments for which the carrying amount does not equal estimated fair value at December 31, 2005 and 2004 were as follows:

	2005				2004
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,136.0	$	3,308.7	$	3,389.5	$	3,699.9
Preferred stock (subject to purchase or sinking funds)		8.2		8.2		9.2		8.5

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, some of which are considered cost basis investments for which determination of fair value historically has been considered impracticable and some of which are otherwise non-marketable, such as life insurance policies.

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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. Life 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.

Telecommunications Investments

In December 2004, SCH sold its investments in ITC^DeltaCom and Knology resulting in losses of $13.9 million, net of taxes. In 2004, SCH recorded an impairment of its investment in Knology totaling $15.0 million, net of taxes.

During 2003, SCH recorded impairment losses associated with its Knology investment totaling $34.6 million, net of taxes.

In May 2003, the Company's investment in ITC Holding Company was sold. The transaction resulted in the receipt of net after-tax cash proceeds of approximately $48 million and the receipt of a minority investment interest in a newly formed entity, Magnolia Holding. A gain, net of tax, of approximately $39 million was recognized upon this transaction.

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 New York Mercantile

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Exchange (NYMEX) futures contracts or options, and over-the-counter instruments such as swaps, which are typically offered by energy and financial institutions.

The Company recognized gains of approximately $4.0 million, $6.4 million and $3.9 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the years ended December 31, 2005, 2004 and 2003, respectively, including recognized gains on cash flow hedges in which the anticipated transaction did not occur. These amounts were recorded in cost of gas. The Company estimates that most of the December 31, 2005 unrealized loss balance of $2.7 million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in 2006 as an increase to gas cost if market prices remain at current levels. As of December 31, 2005, all of the Company's cash flow hedges will settle by their terms before the end of 2007.

PSNC Energy hedges gas purchasing activities using NYMEX futures, options and swaps. PSNC Energy's tariffs include a provision for the recovery of actual gas costs incurred. PSNC Energy records transaction fees and any realized and unrealized gains or losses from derivatives acquired as part of its hedging program in deferred accounts as a regulatory asset or liability for the over- or under-recovery of gas costs.

SCPC'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 SCPC's hedging activities are to be included in the PGA. As such, costs of related derivatives that SCPC utilizes to hedge its gas purchasing activities are recoverable through its 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.

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, 2005 the estimated fair value of the Company's swaps totaled $0.1 million related to combined notional amounts of $47.4 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 also uses interest rate lock or similar agreements to manage interest rate risk. These arrangements are designated as cash flow hedges. As such, payments made upon termination of such agreements are amortized to interest expense over the term of the underlying debt. In connection with the issuance of First Mortgage Bonds in May 2003, the Company paid $11.9 million upon the termination of a treasury lock agreement. In connection with the issuance of First Mortgage Bonds in December 2003, the Company paid $3.5 million upon the termination of a forward starting interest rate swap. In December 2005, the Company entered into a $125 million treasury lock agreement at an initial interest rate of 4.72% which will terminate by August 31, 2006. As of December 31, 2005, an unrealized loss on

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this treasury lock agreement in the amount of $3.8 million has been recorded within other regulatory assets. Any gain or loss on the ultimate settlement of this swap will be amortized over the life of the anticipated debt issuance to which it relates.

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 $10 million per year.

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper, the one-third owner of Summer Station) with 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 $15.6 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident. However, if such an incident were to occur, it would have a material adverse impact on the Company's results of operations, cash flows and financial position.

B. Environmental

South Carolina Electric & Gas Company

In March 2005 the 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. Compliance plans and cost to comply with the rule will be determined once the Company completes its review. 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. The Company is reviewing the final rule. Installation of additional air quality controls is likely to be required to comply with the mercury rule's emission caps. Compliance plans and costs to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates.

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At SCE&G, site assessment and cleanup costs are deferred and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $17.7 million at December 31, 2005. 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. The site is currently being remediated for contamination. SCE&G anticipates that the remaining remediation activities will be completed by mid-2006, with certain monitoring and retreatment activities continuing until 2011. As of December 31, 2005, SCE&G had spent $21.5 million to remediate the Calhoun Park site and expects to spend an additional $0.3 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. Any cost arising from this matter is expected to be recoverable through rates.

Public Service Company of North Carolina, Incorporated

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 approximately $7.4 million, which reflects its estimated remaining liability at December 31, 2005. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates are approximately $3.1 million. Management believes that all MGP cleanup costs will be recoverable through gas rates.

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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 the Company 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.

Post-verdict motions were heard in November 2004 and January 2005. In April 2005, post-trial motions were decided by the Court, and the plaintiff was ordered to elect a single remedy from the multiple jury awards. In response to the April 2005 election order, the plaintiff elected a remedy with damages totaling $18 million, and the Company placed the funds in escrow with the Clerk of Court to forestall the accrual of post-judgment interest. The funds held in escrow are recorded within prepayments and other assets on the balance sheet and appear as an investing activity in the statement of cash flows. The Company believes its accrued liability is still a reasonable estimate. However, the Company continues to believe that the verdict was inconsistent with the facts presented and applicable laws. Both parties have appealed the judgment.

The Company is also defending a claim 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. A bench trial on the indemnification was held on January 14, 2005, and on August 9, 2005 an order was entered against the Company in the amount of $2.6 million. On December 2, 2005, the judge vacated this award, and further motions to review his order are pending. The Company has made provision for this potential loss and further believes that the resolution of this claim will not have a material adverse impact on its results of operations, cash flows or financial condition.

On August 21, 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 utilities' internal use along the electric transmission and distribution line rights-of-way constitutes a trespass. It is anticipated that this case may go to trial in 2006. The Company is confident of the propriety of SCE&G's actions and intend to mount a vigorous defense. The Company further believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.

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On May 17, 2004, the Company was 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 Court (the Court). The plaintiff alleges the Company 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 the Company'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. The Company believes its actions are consistent with governing law and the applicable documents granting easements and rights-of-way. The Court granted the Company's motion to dismiss and issued an order dismissing the case on June 29, 2005. The plaintiff has appealed. The Company intends 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 on October 22, 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 State of South Carolina v. SCE&G claim has been settled by an agreement between the parties, and the settlement has been approved by the court. The allegations were also the subject of a purported class action lawsuit filed in December 2003, against Duke Energy Corporation, Progress Energy Services Company and SCE&G (styled Edwards v. SCE&G), but that case has been dismissed by the plaintiff. In addition, SCE&G filed a petition with the SCPSC on October 23, 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 material loss to the Company.

E. Other Contingency

In 2004 and early 2005, SCANA and certain of its affiliates, like other integrated utilities, were the subject of an investigation by FERC's Office of Market Oversight and Investigations (OMOI) focusing, among other things, on the relationship between SCE&G's merchant and transmission functions. These relationships are among those addressed in FERC Order 2004, a primary purpose of which order is to ensure that affiliates of transmission providers have no marketplace advantage over non-affiliated market participants. In connection with that investigation, SCE&G was assessed no monetary damages or penalties; however, under

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terms of a Settlement and Consent Agreement entered into on April 1, 2005, and approved by FERC order dated April 27, 2005, SCE&G agreed to the implementation of a compliance plan which includes periodic reports to OMOI.

On January 2, 2006, SCE&G provided to FERC a quarterly update on this compliance plan, which included an acknowledgment of SCE&G's discovery that it may have improperly utilized 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 orders under the Federal Power Act that prohibit the use of network transmission service in support of certain "off-system" sales. This acknowledgement was in part the result of SCE&G's preliminary review of a FERC order issued following its examination of another energy provider in September 2005. Upon further review of that order and a comprehensive analysis, SCE&G has now determined and notified FERC that it did improperly utilize network transmission service in a large number of purchase and sale transactions.

In response to this discovery, SCE&G has notified FERC and has ceased participation in such transactions, has instituted additional self-restrictive procedures as safeguards to ensure full compliance in this area in the future, has committed to certain modifications to its compliance plan, including increased levels of training and monitoring, and is fully cooperating with OMOI to resolve this matter.

As of December 31, 2005, SCE&G has recorded a loss accrual in the amount of approximately $0.8 million based on its estimation of net revenues from these transactions that occurred after the date of the Settlement and Consent Agreement and that might be subject to disgorgement pursuant to FERC orders. However, there remains uncertainty as to what additional actions may be taken by FERC. Potential actions could include further modifications to the compliance plan or other non-monetary remedies. In addition to the disgorgement of profits, such remedies could also include penalties of up to a maximum of $1 million per violation or per day since August 8, 2005, the effective date of the Energy Policy Act of 2005. SCE&G estimates that there were approximately 1,200 of these transactions since August 8, 2005, that, despite the immaterial profits from the transactions, could be deemed to be in violation of FERC's rule on the use of network transmission service. In light of SCE&G's self-reporting and other cooperation in the investigation of this matter, SCE&G's belief that no market participants or customers of SCE&G were harmed or disadvantaged by the transactions, and SCE&G's institution of appropriate safeguards referred to above, SCE&G does not believe that such sanctions are warranted. Nonetheless, SCE&G cannot predict what, if any, actions FERC will take with respect to this matter, and is unable to determine if the resolution of this matter will have a material adverse impact on its operations, cash flows or financial condition.

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 $13.9 million, $11.8 million and $12.4 million in 2005, 2004 and 2003,

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respectively. Future minimum rental payments under such leases are as follows:

	Millions of dollars
2006	$	15
2007		13
2008		12
2009		10
2010		1
Thereafter		2

Total	$	53

At December 31, 2005 minimum rentals to be received under noncancelable subleases with remaining lease terms in excess of one year totaled approximately $6.9 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 $2.2 billion, $1.6 billion and $1.2 billion in 2005, 2004 and 2003, respectively. Future payments under such purchase commitments are as follows:

	Millions of dollars
2006	$	1,785
2007		839
2008		734
2009		646
2010		583
Thereafter		4,534

Total	$	9,121

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.

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 SCPC, which is engaged in the purchase, transmission and sale of natural gas on a wholesale basis to distribution companies (including SCE&G), and to industrial customers in South Carolina, and is regulated by the SCPSC.

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

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process and method of distribution. The gas segments differ from each other primarily based on the class of customers each serves and the marketing strategies resulting from those differences. The marketing segments differ from each other primarily based on their respective markets and customer type.

Disclosure of Reportable Segments (Millions of dollars)

2005	Electric Operations			Gas Distribution			Gas Transmission		Gas Retail Marketing		Energy Marketing			All Other			Adjustments/ Eliminations			Consolidated Total
Customer Revenue	$	1,909		$	1,168		$	237	$	664	$	799		$	70		$	(70	)	$	4,777
Intersegment Revenue		4			1			420		—		146			324			(895	)		—
Operating Income		299			75			21		n/a		n/a			n/a			41			436
Interest Expense		13			21			6		2		—			1			169			212
Depreciation and Amortization		450			49			7		3		—			14			(13	)		510
Income Tax Expense (Benefit)		4			18			7		14		(1	)		13			(173	)		(118	)
Net Income (Loss)		n/a			n/a			n/a		24		(1	)		(67	)		364			320
Segment Assets		5,531			1,701			390		284		128			590			895			9,519
Expenditures for Assets		280			122			4		—		1			19			(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			—			339		—		77			304			(724	)		—
Operating Income		550			67			19		n/a		n/a			n/a			(40	)		596
Interest Expense		10			21			5		3		—			—			163			202
Depreciation and Amortization		208			47			7		2		—			12			(11	)		265
Income Tax Expense (Benefit)		(2	)		15			5		18		(1	)		(8	)		96			123
Net Income (Loss)		n/a			n/a			n/a		29		(2	)		(39	)		269			257
Segment Assets		5,365			1,540			362		201		91			501			946			9,006
Expenditures for Assets		389			86			10		—		3			19			(6	)		501
Deferred Tax Assets		n/a			n/a			5		4		3			2			(4	)		10
2003
Customer Revenue	$	1,466		$	870		$	217	$	448	$	416		$	56		$	(57	)	$	3,416
Intersegment Revenue		5			(1	)		303		—		—			277			(584	)		—
Operating Income		426			77			16		n/a		n/a			1			31			551
Interest Expense		7			21			5		4		—			1			162			200
Depreciation and Amortization		183			47			7		1		—			9			(9	)		238
Income Tax Expense (Benefit)		2			19			4		12		(1	)		9			90			135
Net Income (Loss)		n/a			n/a			n/a		20		(1	)		4			259			282
Segment Assets		5,038			1,477			334		133		53			702			721			8,458
Expenditures for Assets		655			68			18		—		—			38			(99	)		680
Deferred Tax Assets		n/a			n/a			5		6		2			44			(57	)		—

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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)

2005 Millions of dollars, except per share amounts	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Annual
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

2004 Millions of dollars, except per share amounts	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Annual
Total operating revenues	$	1,136	$	846	$	857	$	1,046	$	3,885
Operating income		194		123		161		118		596
Net income		101		60		54		42		257
Basic and diluted earnings per share		.91		.54		.48		.37		2.30

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MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

COMMON STOCK INFORMATION

Price Range (New York Stock Exchange Composite Listing):

	2005								2004
	4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.		4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.
High	$	43.37	$	43.65	$	43.30	$	40.04	$	39.71	$	38.09	$	36.88	$	36.29
Low		37.79		39.90		36.56		36.70		36.39		35.66		32.82		33.42

DIVIDENDS PER SHARE

SCANA declared quarterly dividends on its common stock of $.39 per share and $.365 per share in 2005 and 2004, respectively.

The principal market for SCANA common stock is the NYSE, using the ticker symbol SCG. The corporate name SCANA is used in newspaper stock listings. At February 20, 2006 SCANA common stock totaling 115,032,759 shares were held by approximately 35,957 stockholders of record.

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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 a resignation is submitted, or unless the Board of Directors shall otherwise determine. Positions held are for SCANA and all subsidiaries unless otherwise indicated.

Name	Age	Positions Held During Past Five Years	Dates
William B. Timmerman	59	Chairman of the Board, President and Chief Executive Officer	*-present
Joseph C. Bouknight	52	Senior Vice President — Human Resources Vice President Human Resources — Dan River, Inc. — Danville, VA	2004-present *-2004
George J. Bullwinkel	57	President and Chief Operating Officer — SEMI President and Chief Operating Officer — ServiceCare President and Chief Operating Officer — SCI President and Chief Operating Officer — SCPC and SCG Pipeline Senior Vice President — Governmental Affairs and Economic Development	2004-present 2002-present -present 2002-2004 -2002
Sarena D. Burch	49	Senior Vice President —Fuel Procurement and Asset Management — SCE&G, PSNC Energy and SCPC Deputy General Counsel and Assistant Secretary — SCANA Services	2003-present *-2003
Stephen A. Byrne	46	Senior Vice President — Generation, Nuclear and Fossil Hydro — SCE&G Senior Vice President — Nuclear Operations	2004-present *-2004
Paul V. Fant	52	Senior Vice President — SCANA Services Senior Vice President Transmission Services — SCE&G President and Chief Operating Officer — SCPC and SCG Pipeline Executive Vice President — SCG Pipeline Executive Vice President — SCPC	2004-present 2004-present 2004-present 2002-2004 *-2004
Sharon K. Jenkins	48	Senior Vice President — Marketing and Communications — SCANA Services Vice President, Marketing — Wireless and Broadband Systems Division — Motorola, Inc. — Austin, TX	2003-present *-2003
Neville O. Lorick	55	President and Chief Operating Officer — SCE&G	*-present
Kevin B. Marsh	50	Senior Vice President and Chief Financial Officer President and Chief Operating Officer — PSNC Energy	-present -2003
Charles B. McFadden	61	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.	67	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, 2001.

CERTIFICATIONS

Following the 2005 Annual Meeting, SCANA submitted to the New York Stock Exchange (NYSE) the certification of the Chief Financial Officer required by Section 303A.12(a) of the NYSE Listed Company Manual. On March 1, 2006 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

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.(a)	Election of Class I Nominees—	01-James A. Bennett
	Terms Expire 2009	02-William C. Burkhardt
		03-Lynne M. Miller
		04-Maceo K. Sloan
(b)	Election of Class III Nominee Term Expires 2008	05-Sharon A. Decker
2.	Approval of Appointment of Independent Registered Public Accounting Firm

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To vote, mark an 'X' in the appropriate box.

1.: For ALL Nominees / /
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(Write number(s) of nominee(s) below)
2.: For / / Against / / Abstain / /

Dated				, 2006

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 27, 2006 / /

I consent to receive future Proxy Statements and Annual Report Materials through the Internet / /

SCANA CORPORATION
Annual Meeting of Shareholders
April 27, 2006

FORM OF PROXY
SCANA CORPORATION

Proxy Solicited on Behalf of
Board of Directors
The undersigned hereby appoints W.B. Timmerman and K.B. Marsh, 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 27, 2006, 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 enclosed 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 26, 2006
•  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 26, 2006
•  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

PLEASE MARK VOTE /x/

Voting Instructions for Proposals 1 and 2

THE BOARD OF DIRECTORS RECOMMENDS A VOTE "FOR" THE ELECTION OF ALL NOMINEES AS DIRECTORS AND "FOR" PROPOSAL 2.

1.(a)	Election of Class I Nominees—	01-James A. Bennett
	Terms Expire 2009	02-William C. Burkhardt
		03-Lynne M. Miller
		04-Maceo K. Sloan
(b)	Election of Class III Nominee Term Expires 2008	05-Sharon A. Decker
2.	Approval of Appointment of Independent Registered Public Accounting Firm

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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)
2.: For / / Against / / Abstain / /

Dated				, 2006

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 27, 2006 / /

ADMISSION TICKET

SCANA CORPORATION
Annual Meeting of Shareholders
April 27, 2006

8:00 A.M.— Refreshments

9:00 A.M.— Meeting Begins

Leaside

100 East Exchange Place

Columbia, South Carolina 29209

DIRECTIONS TO LEASIDE
FROM CHARLOTTE:
Take I-77 south to Exit 9-A (Garners Ferry Road). Follow the exit onto Garners Ferry Road under I-77. East Exchange Place is the first right turn off Garners Ferry Road immediately past Jim Hudson Automotive Company. Follow to Leaside at end of East Exchange Place. The parking lot is located in front of the building.
		FROM CHARLESTON: Take I-26 to I-77 toward Charlotte. Take Exit 9 and turn right at traffic light onto Garners Ferry Road. East Exchange Place is the first right turn off Garners Ferry Road immediately past Jim Hudson Automotive Company. Follow to Leaside at end of East Exchange Place. The parking lot is located in front of the building. FROM GREENVILLE: Take I-26 to I-77 toward Charlotte. Take Exit 9 and turn right at traffic light onto Garners Ferry Road. East Exchange Place is the first right turn off Garners Ferry Road immediately past Jim Hudson Automotive Company. Follow to Leaside at end of East Exchange Place. The parking lot is located in front of the building.
FROM FIVE POINTS (COLUMBIA):
Take US 378/76—east (Devine Street/Garners Ferry Road) past the Veterans Administration Hospital and under I-77 overpass. East Exchange Place is the first right turn off Garners Ferry Road immediately past Jim Hudson Automotive Company. Follow to Leaside at end of East Exchange Place. The parking lot is located in front of the building.

Proxy Notification

Dear Shareholder,

You have elected to receive your 2006 Proxy Statement and 2005 Annual Report electronically.

SCANA Corporation has made available on-line its 2006 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

March 17, 2006

Dear Shareholders:

Enclosed are the 2006 SCANA Corporation proxy materials, including SCANA's annual financial statements, management's discussion and analysis of financial condition and results of operations and related annual report information.

The Chairman's letter contained in the 2006 Proxy Statement refers to the Company's 2005 Annual Report, which we typically include in this mailing. However, due to a printing delay, it will be sent to you in a separate mailing.

We apologize for this delay and appreciate your understanding.

Lynn M. Williams
Corporate Secretary

QuickLinks

SCANA Corporation 1426 Main Street Columbia, South Carolina 29201 PROXY STATEMENT
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
Long-Term Incentive Plans Awards in Last Fiscal Year
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