Edgar Filing: SCANA CORP

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SCHEDULE 14A INFORMATION

Proxy Statement Pursuant to Section 14(a) of
the Securities Exchange Act of 1934 (Amendment No. )

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SCANA CORPORATION
(Name of Registrant as Specified In Its Charter)

(Name of Person(s) Filing Proxy Statement, if other than the Registrant)

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		Your VOTE Is Important



		SCANA Corporation 2003 Proxy Statement

				Notice of Annual Meeting, Proxy Statement for Annual Meeting, Annual Financial Statements, Management's Discussion and Analysis and Other Company Information

March 17, 2003

Dear Shareholders:

You are cordially invited to attend the Annual Meeting of Shareholders to be held on Thursday, May 1, 2003. The meeting will be held in the Geneen Auditorium, The Fuqua School of Business, Duke University, One Science Drive, Durham, North Carolina. You will find directions to The Fuqua School of Business on the back of the enclosed admission ticket. Valet parking will be provided for your convenience.

•: The approximate date of mailing for this proxy statement and enclosures is March 17, 2003. In order to reduce production costs, we are including SCANA's annual financial statements, management's discussion and analysis of financial condition and results of operations and other Company information in the Proxy Statement.
•: You will find a Notice of Meeting on page 1 identifying two proposals that will be presented at the Annual Meeting.
•: At the meeting, we will give you a brief report on SCANA's 2002 business results.
•: If you plan to attend the meeting, please so indicate on the enclosed proxy card.
•: If you will need special assistance at the meeting because of a disability, 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 24, 2003.
•: Refreshments will be served beginning at 8:00 a.m., in the atrium of The Fuqua School of Business.

Your vote is important. We encourage you to read this Proxy Statement and vote your shares as soon as possible. A postage-paid return envelope for your proxy card is enclosed for your convenience. SCANA shareholders also can vote their proxies electronically — by telephone or Internet. Telephone or 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 will again have an opportunity during this year's voting process to elect to view future proxy statements and annual reports on the Internet, rather than receive paper copies in the mail. Electing this option will help us reduce printing and postage costs, and is more environmentally friendly. Additional information may 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		1
VOTING PROCEDURES		2
DIRECTOR COMPENSATION		4
BOARD MEETINGS — COMMITTEES OF THE BOARD		5
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION		7
RELATED PARTY TRANSACTIONS		7
ELECTION OF DIRECTORS		7
PROPOSAL 1 — NOMINEES FOR CLASS I DIRECTORS		8
CONTINUING DIRECTORS		9
SHARE OWNERSHIP OF DIRECTORS, NOMINEES AND EXECUTIVE OFFICERS		11
FIVE PERCENT OWNERSHIP OF SCANA COMMON STOCK		12
EXECUTIVE COMPENSATION		13
	Summary Compensation Information	13
	Option Grants and Related Information	14
	Defined Benefit Plans	15
	Termination, Severance and Change In Control Arrangements	15
REPORT ON EXECUTIVE COMPENSATION		17
HUMAN RESOURCES COMMITTEE CHARTER		20
PERFORMANCE GRAPH		22
AUDIT COMMITTEE REPORT		24
PROPOSAL 2 — APPROVAL OF APPOINTMENT OF EXTERNAL AUDITORS		25
AUDIT COMMITTEE CHARTER		26
OTHER INFORMATION		30
	Section 16(a) Beneficial Ownership Reporting Compliance	30
	Shareholder Proposals and Recommendations for a Director Nominee	30
	Expenses of Solicitation	30
	Tickets to the Annual Meeting	30
	Availability of Form 10-K	31
APPENDIX A — Annual Financial Statements, Management's Discussion and Analysis and Other Company Information

NOTICE OF ANNUAL MEETING

Meeting Date:		Thursday, May 1, 2003
Meeting Time:		9:00 A.M., Eastern Daylight Savings Time
Meeting Place:		Geneen Auditorium, The Fuqua School of Business Duke University One Science Drive Durham, North Carolina
Meeting Record Date:		March 10, 2003
Meeting Agenda:		1) Election of Class I Directors 2) Approval of Appointment of External Auditors

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, during business hours from March 17, 2003 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 30.

By Order of the Board of Directors

Lynn M. Williams
Corporate Secretary

PLEASE SIGN, DATE AND MAIL YOUR PROXY TODAY IN THE ENVELOPE ENCLOSED OR YOU MAY VOTE ELECTRONICALLY BY TELEPHONE OR INTERNET. THE ENCLOSED PROXY CARD GIVES DETAILED INSTRUCTIONS ON TELEPHONE AND INTERNET VOTING.

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. Our telephone and Internet voting procedures have been designed to validate the shareholder by using individual control numbers. Your control number appears on your proxy card.

Vote By Telephone:

You may vote your shares by telephone by calling the toll-free telephone number shown on your proxy card. You must have a touch-tone phone to use this option. Telephone voting is available 24 hours a day, seven days a week. Clear and concise voice prompts allow you to vote your shares and confirm that your instructions have been properly recorded. You may also consent to view future proxy statements and annual reports on the Internet instead of receiving them through the mail. If you vote by telephone, you do NOT need to return your proxy card.

Vote By Internet:

You may vote through the Internet. The web site for Internet voting is shown on your proxy card. Internet voting is available 24 hours a day, seven days a week. You will be given the opportunity to confirm that your instructions have been properly recorded. You may also consent to view future proxy statements and annual reports on the Internet instead of receiving them through the mail. If you vote through the Internet, you do NOT need to return your proxy card.

Vote By Mail:

If you choose to vote by mail, simply mark the enclosed proxy card, date and sign it, and return it to SCANA in the postage-paid envelope provided. If you wish to view future proxy statements and annual reports on 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 in accordance with your directions. 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 included by your broker or nominee.

Changing Your Proxy Vote

You may change 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 accomplish this by submitting new voting instructions to your broker or nominee.

Voting By Savings Plan Participants

If you own SCANA shares 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 trustee for the plan.

Vote Required and Method of Counting Votes

At the close of business on the record date, March 10, 2003, there were 110,665,096 shares outstanding and entitled to vote at the Annual Meeting. Each share is entitled to one vote on each item.

The presence, in person or by proxy, of the holders of a majority of the shares entitled to be voted 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 item because the nominee does not have discretionary voting power for that particular item and has not received instructions from the beneficial owner.

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 four individuals who receive the largest number of votes cast for Class I Directors will be elected as directors. Votes indicated as "withheld" and broker "non-votes" will not be cast for nominees.

SCANA knows of no reason why any of the nominees for director named herein would 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 (unless designated to the contrary) will be voted for such other person or persons as the Board of Directors may recommend.

Proposal 2 — Approval of Appointment of External Auditors

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 vote.

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 persons named in the accompanying proxy card intend to vote the shares represented by them in accordance with their best judgment.

View Proxy Statements and Annual Reports on the Internet

SCANA shareholders may elect to view all future proxy statements and annual reports on the Internet instead of receiving them by U.S. mail each year. If you choose to access future proxy statements and annual reports online, you will be notified of the web site access address and other necessary information to view the proxy material and to submit your vote. Please be aware that if you choose to view your proxy materials on 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 on the Internet, respond to the question when prompted. If you vote by mail, please mark the box on your proxy card.

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

DIRECTOR COMPENSATION

Board Fees

Officers of SCANA who are also directors do not receive additional compensation for their service as directors. Since July 1, 2000, compensation for non-employee directors has included the following:

•: an annual retainer of $30,000 (60% of the annual retainer fee is paid in shares of SCANA Common Stock);
•: $3,500 for each board meeting attended;
•: $3,000 for attendance at a committee meeting held on a day other than a regular meeting of the Board;
•: $250 for participation in a telephone conference meeting;
•: $2,000 for attendance at an all-day conference; and
•: reimbursement for expenses incurred in connection with all of the above.

Director Compensation and Deferral Plans

Since January 1, 2001, non-employee director compensation deferrals have been governed by the SCANA Corporation 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 2002, the only director remaining in the Voluntary Deferral Plan was Mr. Bennett, whose account was credited with interest of $2,567 for the year.

Under the new plan, a director may elect to defer the 60% of the annual retainer fee required to be paid in 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 may also elect to defer the 40% of the annual retainer fee not required to be paid in stock and 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 amounts may be elected to be paid in cash when accrued or retained to invest in hypothetical shares of SCANA Common Stock. Amounts payable in cash accrue interest earnings until paid.

During 2002, Ms. Miller and Messrs. Amick, Bennett, Burkhardt, Hipp, Sloan, Stowe and York 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. In addition, Mr. Hagood elected to defer 60% of his annual retainer and earnings under the plan 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 a tax deductible, charitable contribution 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 in-state institutions of higher education must be approved by the Chief Executive Officer of SCANA. Any out-of-state designation 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 program.

BOARD MEETINGS — COMMITTEES OF THE BOARD

The Board held four meetings in 2002. Each director attended at least 75% of all Board and applicable committee meetings during 2002. This table describes the Board's Committees, which include an audit committee, an executive committee (which acts as the nominating committee) and two committees that deal with compensation issues (the Human Resources Committee and the Long-Term Equity Compensation Plan Committee).

NAME OF COMMITTEE AND MEMBERS	FUNCTIONS OF THE COMMITTEE	NUMBER OF MEETINGS IN 2002


EXECUTIVE COMMITTEE W. B. Timmerman, Chairman B. L. Amick W. H. Hipp L. M. Miller M. K. Sloan G. S. York	• provides counsel to the Chief Executive Officer • reviews management's long range strategic plans, goals and objectives • reviews budgets, financial plans, plans for debt financing and the financing of acquisitions, investments and capital expenditures of a major nature • reviews and recommends actions relating to dividends • monitors advertising and philanthropic activities • recommends levels of expenditures to the Board • recommends the slate of director nominees to be presented for election at each annual meeting • recommends assignments of directors to serve on Board Committees • reviews outside relationships, including those with governments, other businesses and the community • reviews the impact of regulations, litigation and any public policy controversy that may affect SCANA	4 Meetings

HUMAN RESOURCES COMMITTEE W. C. Burkhardt, Chairman B. L. Amick W. B. Bookhart, Jr. D. M. Hagood M. K. Sloan H. C. Stowe	• reviews and makes recommendations to the Board with respect to compensation plans • recommends to the Board persons to serve as officers of SCANA and its subsidiaries • recommends to the Board salary and compensation levels, including fringe benefits, for officers and directors of SCANA and its subsidiaries • approves goals and objectives with respect to the compensation of the chief executive officer, evaluates the chief executive officer's performance and sets his compensation based on this evaluation • reviews 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 welfare 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 bonus and incentive programs • evaluates annually its own performance and the adequacy of its charter	4 Meetings


LONG-TERM EQUITY COMPENSATION PLAN COMMITTEE W. C. Burkhardt, Chairman B. L. Amick J. A. Bennett W. B. Bookhart, Jr. E. T. Freeman D. M. Hagood L. M. Miller M. K. Sloan H. C. Stowe G. S. York	• administers the SCANA Corporation Long-Term Equity Compensation Plan	1 Meeting

AUDIT COMMITTEE E. T. Freeman, Chairman J. A. Bennett D. M. Hagood H. C. Stowe G. S. York	• periodically meets separately with management, internal auditors and external auditors to discuss and evaluate the scope and results of audits and SCANA's accounting procedures and controls • 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) external auditors • maintains responsibility for 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	9 Meetings

NUCLEAR OVERSIGHT COMMITTEE L. M. Miller, Chairman J. A. Bennett W. B. Bookhart, Jr. W. C. Burkhardt E. T. Freeman	• monitors SCANA's nuclear operations • meets periodically with SCANA management to discuss and evaluate nuclear operations, including regulatory matters, operating results, training and other related topics • tours the V.C. Summer Nuclear Station plant and training facilities at least once a year • periodically presents an independent report to the Board on the status of SCANA's nuclear operations	4 Meetings

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

During 2002, decisions on various elements of executive compensation were made by the Human Resources Committee and the Long-Term Equity Compensation Plan Committee. No officer, employee or former officer of SCANA or any of its subsidiaries served as a member of the Human Resources Committee or the Long-Term Equity Compensation Plan Committee.

The names of the persons who serve on the Human Resources Committee and the Long-Term Equity Compensation Plan Committee can be found on page 19.

RELATED PARTY TRANSACTIONS

During 2002, SCANA paid $63,911 (including the value of non-utility in-kind services provided by SCANA and its subsidiaries) to subsidiaries of The Liberty Corporation for advertising expenses. SCANA's management believes that these services, the majority of which were arranged through the use of an independent third-party advertising agency, were provided at competitive market rates.

Mr. Hipp is Chairman and Chief Executive Officer and a director of The Liberty Corporation. It is anticipated that similar transactions will occur in the future.

ELECTION OF DIRECTORS

SCANA currently has 12 directors. The Board is divided into three classes with the members of each class serving a three-year term. The terms of the Class I Directors will expire at the Annual Meeting.

All of the current Class I directors, Ms. Miller and Messrs. Bennett, Burkhardt and Sloan, are being nominated for re-election. The terms of the Class I directors elected at the Annual Meeting will expire in 2006.

The information set forth on the following pages concerning the nominees and continuing directors has been furnished to SCANA by such persons. Each of the directors is also a director of South Carolina Electric & Gas Company and Public Service Company of North Carolina, Incorporated, subsidiaries of SCANA.

PROPOSAL 1 — NOMINEES FOR CLASS I DIRECTORS
TERMS TO EXPIRE AT THE ANNUAL MEETING IN 2006

		James A. Bennett (Age 42)		Director since 1997 Shares: 2,366
		Mr. Bennett has been Executive Vice President and Director of Public Affairs, First Citizens Bank in Columbia, South Carolina ("First Citizens") since August 2002. He was President and Chief Executive Officer of South Carolina Community Bank, also in Columbia, from May 2000 to July 2002. He was Economic Development Director, First Citizens, from February 2000 to May 2000. From December 1998 until February 2000, he was Senior Vice President and Director of Professional Banking, and, from December 1994 until December 1998, he was Senior Vice President and Director of Community Banking, at First Citizens.
		William C. Burkhardt (Age 65)		Director since 2000 Shares: 12,143
		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, located in Cary, North Carolina in May 2000, having served in that position since 1980. Mr. Burkhardt is a director of Capital Bank and Industrial Microwave Systems.
		Lynne M. Miller (Age 51)		Director since 1997 Shares: 3,480
		Ms. Miller has been Chief Executive Officer of Environmental Strategies Corporation, an environmental consulting and engineering firm headquartered in Reston, Virginia, since February 1998. Ms. Miller is a director of Adams National Bank, a subsidiary of Abigail Adams National Bancorp, Inc.
		Maceo K. Sloan (Age 53)		Director since 1997 Shares: 4,317
		Mr. Sloan is Chairman, President and Chief Executive Officer of Sloan Financial Group, Inc., a holding company, and Chairman and Chief Executive Officer of NCM Capital Management Group, Inc., an investment management company ("NCM"), both located in Durham, North Carolina. He has held these positions for more than five years. He has also been Chief Investment Officer of NCM since January 2003. Mr. Sloan is a trustee of Teachers Insurance Annuity Association-College Retirement Equity Fund (TIAA-CREF) and a director of M&F Bancorp.

CONTINUING DIRECTORS
CLASS II DIRECTORS–TERMS EXPIRING AT THE ANNUAL MEETING IN 2004

		William B. Bookhart, Jr. (Age 61)		Director since 1979 Shares: 22,565
		Mr. Bookhart is a partner in Bookhart Farms, which operates a general farming business in Elloree, South Carolina and has held this position for more than five years.
		W. Hayne Hipp (Age 63)		Director since 1983 Shares: 4,897
		Mr. Hipp is Chairman and Chief Executive Officer of The Liberty Corporation, a broadcasting holding company headquartered in Greenville, South Carolina. He has held these positions for more than five years. Mr. Hipp is a director of The Liberty Corporation.
		Harold C. Stowe (Age 56)		Director since 1999 Shares: 4,299
		Mr. Stowe has been President of Canal Holdings, LLC, a forest products industry company and its predecessor company, in Conway, South Carolina for more than five years. Mr. Stowe is a director of Canal Holdings, LLC and Ruddick Corporation.
		G. Smedes York (Age 62)		Director since 2000 Shares: 11,727
		Mr. York has been President and Treasurer of York Properties, Inc., a full-service commercial and residential real estate company in Raleigh, North Carolina for more than five years.

CONTINUING DIRECTORS
CLASS III DIRECTORS–TERMS EXPIRING AT THE ANNUAL MEETING IN 2005

		Bill L. Amick (Age 59)		Director since 1990 Shares: 11,048
		Mr. Amick is Chairman of the Board and Chief Executive Officer of Amick Farms, Inc., Amick Processing, Inc. and Amick Broilers, Inc., a vertically integrated broiler operation in 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.
		Elaine T. Freeman (Age 67)		Director since 1992 Shares: 6,703
		Mrs. Freeman is Executive Director of ETV Endowment of South Carolina, Inc., a non-profit organization located in Spartanburg, South Carolina. She has held this position for more than five years. Mrs. Freeman is a director of the National Bank of South Carolina (a member bank of Synovus Financial Corporation).
		D. Maybank Hagood (Age 41)		Director since 1999 Shares: 850
		Mr. Hagood is President and Chief Executive Officer of William M. Bird and Company, Inc., a wholesale distributor of floor covering materials located in Charleston, South Carolina. He has held this position for more than five years.
		William B. Timmerman (Age 56)		Director since 1991 Shares: 251,584*
		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. Mr. Timmerman is a director of ITC^DeltaCom, Inc. and The Liberty Corporation.

* Includes 195,208 shares subject to currently exercisable options and options that will become exercisable within 60 days.

SHARE OWNERSHIP OF DIRECTORS, NOMINEES AND EXECUTIVE OFFICERS

In general, "beneficial ownership" includes those shares a director, nominee or executive officer has the power to vote or transfer. On February 28, 2003, the directors and executive officers of SCANA as a group (20 persons) beneficially owned, in the aggregate, 725,463 shares of SCANA Common Stock, including 467,027 shares subject to currently exercisable options and options that will become exercisable within 60 days (approximately .7% of the shares outstanding and entitled to vote at the Annual Meeting).

The following table lists shares beneficially owned on February 28, 2003 by each director, each nominee and each person named in the Summary Compensation Table on page 13.

Name		*Amount and Nature of Beneficial Ownership of SCANA Common Stock^{(1)(2)(3)(4)(5)}**
B. L. Amick		11,048
H. T. Arthur		51,343
J. A. Bennett		2,366
W. B. Bookhart, Jr		22,565
G. J. Bullwinkel		63,313
W. C. Burkhardt		12,143
E. T. Freeman		6,703
D. M. Hagood		850
W. H. Hipp		4,897
N. O. Lorick		69,456
K. B. Marsh		79,126
L. M. Miller		3,480
M. K. Sloan		4,317
H. C. Stowe		4,299
W. B. Timmerman		251,584
G. S. York		11,727

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

(1): Includes shares owned by close relatives, the beneficial ownership of which is disclaimed by the director, nominee or named executive officer, as follows: Mr. Amick — 480; Mr. Bookhart — 6,335; and by all directors, nominees and named executive officers 6,815 in total.
(2): Includes shares purchased through February 28, 2003, by the Trustee under SCANA's Stock Purchase Savings Plan.
(3): Hypothetical shares acquired under the SCANA Director Compensation and Deferral Plan are not included in the above table. As of February 28, 2003, each of the following directors had acquired under the plan, the number of hypothetical shares following his or her name: Messrs. Amick — 5,044; Bennett — 5,715; Burkhardt — 5,939; Hagood — 1,988; Hipp — 5,327; Sloan — 5,218; Stowe — 5,022; York — 5,567 and Ms. Miller — 5,718.
(4): Includes shares subject to currently exercisable options and options that will become exercisable within 60 days in the following amounts: Messrs. Timmerman — 195,208; Arthur — 35,888; Bullwinkel — 32,798; Lorick — 52,745; and Marsh — 62,040.
(5): Hypothetical shares acquired under the SCANA Executive Deferred Compensation Plan are not included in the above table. As of February 28, 2003, each of the following officers had acquired under the plan, the number of hypothetical shares following his name: Messrs. Timmerman — 18,681; Arthur — 2,806; Bullwinkel — 4,017; Lorick — 2,531; and Marsh — 4,394.

FIVE PERCENT OWNERSHIP OF SCANA COMMON STOCK

The share ownership indicated below for the SCANA Corporation Stock Purchase Savings Plan ("SPSP") is based on a Form 13G dated February 12, 2003 and the share ownership for FMR Corporation is based on a Form 13G dated February 14, 2003, both of which were filed with the Securities and Exchange Commission. Except as set forth below, to SCANA's knowledge as of March 10, 2003, no person owned beneficially 5% or more of SCANA's Common Stock.

Name and Address of Beneficial Owner		Amount and Nature of Beneficial Ownership		Percent of Class
SCANA Corporation Stock Purchase Savings Plan c/o AMVESCAP National Trust Company, as Trustee 400 Colony Square, Suite 2200 1201 Peachtree Street, N.E. Atlanta, GA 30361		10,186,981	⁽¹⁾	9.2	%
FMR Corporation 82 Devonshire Street Boston, Massachusetts 02109		6,494,597	⁽²⁾	5.9	%

(1): The SPSP has shared power to vote and dispose of all of the shares reported as owned.
(2): FMR Corporation has sole power to vote 376,177 of the shares and sole power to dispose of all of the shares.

EXECUTIVE COMPENSATION

Summary Compensation Information

The following table contains information with respect to compensation paid or accrued during the years 2002, 2001 and 2000, to the Chief Executive Officer of SCANA Corporation and certain other highly compensated persons who were executive officers of SCANA during 2002.



SUMMARY COMPENSATION TABLE


			Annual Compensation			Long-Term Compensation Awards

Name and Principal Position	Year		Salary ($)	Bonus⁽¹⁾ ($)	Other Annual Compensation⁽²⁾ ($)	Securities Underlying Option SARS (#)	LTIP Payouts⁽³⁾ ($)	All Other Compensation⁽⁴⁾ ($)

W. B. Timmerman Chairman, President and Chief Executive Officer; Director — SCANA Corporation	2002 2001 2000	⁽⁵⁾	751,228 660,238 524,261	760,949 0 354,486	16,435 17,611 17,888	219,200 129,781 35,620	536,884 0 0	44,614 60,884 50,230
N. O. Lorick President and Chief Operating Officer —South Carolina Electric & Gas Company	2002 2001 2000		376,538 385,252 167,778	317,808 0 124,921	16,958 18,701 7,313	77,816 36,711 2,332	145,487 0 0	22,132 30,611 12,728
K. B. Marsh Senior Vice President and Chief Financial Officer — SCANA Corporation	2002 2001 2000		375,384 334,234 276,172	317,808 0 150,720	10,183 10,554 10,613	77,816 36,711 11,627	209,432 0 0	22,063 29,097 24,254
G. J. Bullwinkel President and Chief Operating Officer —South Carolina Pipeline Corporation	2002 2001 2000		305,332 260,812 249,037	176,628 0 120,480	13,993 14,248 14,340	42,341 19,142 8,796	146,345 0 0	17,860 22,878 20,572
H. T. Arthur Senior Vice President and General Counsel — SCANA Corporation	2002 2001 2000		297,115 270,963 234,812	191,340 0 120,480	15,830 16,119 16,119	42,992 19,142 8,796	146,345 0 0	17,367 23,487 19,718

(1): Payments under the Annual Incentive Plan.
(2): For 2002, other annual compensation consists of automobile allowance and life insurance premiums on policies owned by named executive officers of $9,000 and $7,435 for Mr. Timmerman; $9,000 and $7,958 for Mr. Lorick; $9,000 and $1,183 for Mr. Marsh; $9,000 and $4,993 for Mr. Bullwinkel; and $9,000 and $6,830 for Mr. Arthur.
(3): Payouts under Performance Share Plan.
(4): All other compensation for all named executive officers consists solely of matching contributions to defined contribution plans.
(5): Reflects actual salary paid in 2002. Base salary of $761,000, as referenced on page 19, became effective on February 21, 2002.

Options Grants and Related Information

Option/SAR Grants in Last Fiscal Year

Individual Grants						Potential Realizable Value at Assumed Annual Rates of Stock Price Appreciation for Option Term
(a)	(b)	(c)	(d)		(e)	(f)		(g)
Name	Number of Securities Underlying Options/ SARs Granted	% of Total Options/ SARs Granted to Employees in Fiscal Year	Exercise or Base Price ($/Sh)		Expiration Date	5% ($)		10% ($)
W. B. Timmerman	219,200	19.63	$	27.52	02/21/12	$	3,793,734	$	9,614,067
N. O. Lorick	77,816	6.97		27.52	02/21/12		1,346,776		3,412,994
K. B. Marsh	77,816	6.97		27.52	02/21/12		1,346,776		3,412,994
G. J. Bullwinkel	33,724	3.02		27.52	02/21/12		583,667		1,479,128
G. J. Bullwinkel	8,617	.77		29.60	08/01/12		160,408		406,505
H. T. Arthur	42,992	3.85		27.52	02/21/12		744,070		1,885,620

All the above options vest 33¹/3% on each of the first, second and third anniversaries of the date of the grant, February 21, 2002 and August 1, 2002, as applicable.

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

(a)	(d)	(e)
	Number of Securities Underlying Unexercised Option/SARs At FY-End (#)	Value of Unexercised In-the-Money Options/ SARs at FY-End ($)⁽¹⁾
Name	Exercisable/ Unexercisable	Exercisable/ Unexercisable
W. B. Timmerman	67,007/317,594	$	281,501/$1,122,564
N. O. Lorick	13,792/103,067		51,440/357,835
K. B. Marsh	19,988/106,166		85,274/374,752
G. J. Bullwinkel	12,245/58,034		54,414/188,531
H. T. Arthur	12,245/58,685		54,414/208,693

(1): Based on the closing price of $30.96 per share on December 31, 2002, the last trading day of the fiscal year.

Defined Benefit Plans

SCANA sponsors a tax qualified defined benefit retirement plan. The plan has a mandatory cash balance benefit formula (the "Cash Balance 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 benefit formula or switching to the cash balance benefit option. All the executive officers named in the Summary Compensation Table elected to participate under the cash balance option of the plan.

The Cash Balance Formula benefit is expressed in the form of a hypothetical account balance. Participants electing to participate under the cash balance option had an opening account balance established for them. The opening account balance was equal to the present value of the participant's June 30, 2000 accrued benefit under the final average pay formula. Participants who had 20 years of vesting service or who had 10 years of vesting service and whose age plus service equaled at least 60 were given transition credits. For these participants, the beginning account balance was determined so that projected benefits under the cash balance option approximated projected benefits under the final average pay formula at the earliest date at which unreduced benefits are payable under the plan.

Account balances are increased monthly by interest and compensation credits. The interest rate used for accumulating account balances changes annually and is equal to the average rate for 30-year Treasuries for December of the previous calendar year. Compensation credits equal 5% of compensation under 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 sponsors 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 plans, 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 — $474,672; Mr. Lorick — $305,292; Mr. Marsh — $367,140; Mr. Bullwinkel — $310,524; and Mr. Arthur — $114,516.

Termination, Severance and Change in Control Arrangements

SCANA maintains an Executive Benefit Plan Trust. The purpose of the trust is to assist in retaining and attracting quality leadership in key SCANA positions in the current transitional environment of the utilities industry. 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 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): 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 operative for a period of

24 months following a Change in Control where 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 in lieu of those otherwise provided under plans (1) through (4) 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 Change in Control and (ii) the officer's target annual incentive award in effect as of the Change in Control under the 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 where the Key Executive Severance Benefits Plan is operable are:

•: 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 targeted performance share awards 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 term.
•: A benefit distribution under the 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 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 on the date 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 rewards to corporate and business unit results;
•: 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 SCANA's goal of enhancing shareholder value.

A description of the program and a discussion of Mr. Timmerman's 2002 compensation follows.

Program Elements

During 2002, executive compensation consisted primarily of three key components: base salary, short-term incentive compensation (Annual Incentive Plan) and long-term incentive compensation (Long-Term Equity Compensation Plan and Performance Share Plan).

Compensation levels are established annually based on a comparison to a market, which consists of utilities of various sizes, smaller telecommunications companies and general industry. Results are adjusted through regression analysis to account for differences in company size. Some of the companies listed on page 22 under the caption "Performance Graph" are included in the market comparator group. We do not include all of the peer group utility companies in the market comparator group because we believe that SCANA's competition for executives does not include all of those companies and includes other utilities, smaller telecommunications companies and general industry companies.

For 2002, all elements of executive compensation, with the exception of perquisites, were below the market median as adjusted for company size. The combined effect of increasing short-term incentive targets and continuing to move targeted compensation levels toward the market median has improved SCANA's position relative to the market. However, total target compensation is still below the market median.

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 salaries are reviewed annually by the Human Resources Committee. Adjustments may be 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 pay practices.

Annual Incentive Plan

SCANA's Annual Incentive Plan for its officers and officers of its subsidiaries promotes SCANA's pay-for-performance philosophy, as well as its goal of having a meaningful amount of executive pay "at-risk." Through this plan, financial incentives are provided in the form of annual cash bonuses.

Executives eligible for this plan are assigned threshold, target and maximum bonus levels as a percentage of salary. Bonuses earned are based on the level of performance achieved. Award payouts may increase to a maximum of 1.5 times target if performance exceeds the goals established. Award payouts may decrease, generally to a minimum of

one-half the target-level awards, if performance fails to meet established targets, but results are achieved at minimum or threshold levels. Awards earned based on the achievement of pre-established goals may nonetheless be decreased if the Human Resources Committee determines that actual results warrant a lower payout.

For 2002, the Annual Incentive Plan placed equal emphasis on achieving profitability targets and meeting annual business objectives relating to such matters as efficiency, quality of service, customer satisfaction 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 meeting its annual business objectives for 2002, participants in the plan received payouts for 2002.

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 Long-Term Equity Compensation Plan Committee believes this approach to total compensation opportunities provides the appropriate focus for those officers and other key employees who are charged with the responsibility for managing SCANA and achieving success for its shareholders. A portion of each executive's potential compensation consists of awards under the Long-Term Equity Compensation Plan. The committee may award to eligible employees, 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. In 2002, awards under the Long-Term Equity Compensation Plan consisted exclusively of nonqualified stock option grants.

Nonqualified Stock Option Grants

The nonqualified stock options granted in 2002 give officers the right to purchase shares of SCANA Common Stock at the fair market value of a share on the date the options were granted. Each option has a 10 year term and becomes exercisable in 33¹/3% increments on each of the first three anniversaries of the grant date. The purpose of stock options is to align compensation directly with increases in shareholder value. Accordingly, these options will be valuable to recipients only if the market price of SCANA's stock increases.

2002 Payouts Under Performance Share Plan

Prior to the adoption of the Long-Term Equity Compensation Plan, long-term compensation awards were made under SCANA's Performance Share Plan. The last awards under that plan were made in 2000. Under target awards made in 2000 for the 2000-2002 performance period, payouts were to occur if SCANA's total shareholder return ("TSR") was in the top two-thirds of the peer group over the period. TSR is stock price increase over the period, plus cash dividends paid during that period, divided by stock price as of the beginning of the period. The peer group includes SCANA and 61 other electric and gas utilities listed on page 22, none of which have annual revenues of less than $100 million.

Under the terms of the 2000 awards, executives were to earn threshold payouts of 0.4 times target at the 33rd percentile of three-year performance, target payouts at the 50th percentile and maximum payouts at 1.5 times target if SCANA's TSR was at or above the 75th percentile. No payouts were to be earned if performance was at less than the 33rd percentile.

For the three-year performance period 2000-2002, SCANA's TSR was at the 62nd percentile of the peer group. This resulted in payouts being made at 124% of 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 for certain executive officers that exceeds $1,000,000. 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 committees responsible for compensation matters have not adopted a policy that all compensation must be deductible.

2002 Compensation of Chief Executive Officer

For 2002, Mr. Timmerman's compensation consisted of the following:

•: Base salary of $761,000 derived by reference to executive pay for the market group described above. The salary increase of $84,700 from $676,300 to $761,000 was based on his responsibilities as Chairman, President and Chief Executive Officer, external pay practices 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 2002, Mr. Timmerman's Annual Incentive Plan target award was 75% of the control point for his salary grade. Mr. Timmerman's 2002 award 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 120% of target.
•: As discussed above, SCANA's results relative to the peer group for the 2000-2002 performance period were at the 62nd percentile, resulting in a payout of 124% of target under the Performance Share Plan.
•: In 2002, Mr. Timmerman's Long-Term Equity Compensation Plan target was set at 125% of the control point for his salary grade. This resulted in an award of 219,200 stock options. The amount of the award was determined by the Long-Term Equity Compensation Plan Committee based on Mr. Timmerman's salary, level of responsibility and competitive practices.

Human Resources Committee		Long-Term Equity Compensation Plan Committee
W. C. Burkhardt*		W. C. Burkhardt *
B. L. Amick		B. L. Amick
W. B. Bookhart, Jr.		J. A. Bennett
D. M. Hagood		W. B. Bookhart, Jr.
M. K. Sloan		E. T. Freeman
H. C. Stowe		D. M. Hagood
		L. M. Miller
		M. K. Sloan
		H. C. Stowe
		G. S. York

*Chairman of the Committee

HUMAN RESOURCES COMMITTEE CHARTER

Purpose

The purpose of the Human Resources Committee (the "Committee") of the Board of Directors (the "Board") of SCANA Corporation ("SCANA") is to discharge the responsibilities of the Board relating to compensation of SCANA's executives and SCANA's long-term strategic plans and performance of SCANA's management of all human resources, including safety, health, labor/employee relations and equality of treatment; to produce an annual report on executive compensation for inclusion in SCANA's proxy statement, in accordance with applicable rules and regulations of the Securities and Exchange Commission; and to have such other powers and perform such other duties as the Board may from time to time delegate to the Committee, including those set forth below:

Duties and Responsibilities

•: Review and make recommendations to the Board with respect to compensation plans, including incentive compensation plans and equity based plans;
•: Recommend to the Board, persons to serve as officers of SCANA and its subsidiaries;
•: Recommend to the Board, salary and compensation levels, including fringe benefits for officers and directors of SCANA and its subsidiaries;
•: Review and approve corporate goals and objectives with respect to the compensation of the Chief Executive Officer, evaluate the Chief Executive Officer's performance in light of those goals and objectives and set the Chief Executive Officer's compensation level based on this evaluation;
•: Review management's resources and development with the Chief Executive Officer and recommend to the Board succession plans for senior management;
•: Review the investment policies of SCANA's Retirement Plan;
•: Provide direction regarding the operation of SCANA's Retirement Plan and other employee welfare benefit plans;
•: Review SCANA's long range strategic plans and performance in regard to its management of all human resources, including safety, health, labor/employee relations and equality of treatment;
•: Review SCANA's active operating performance relative to the bonus and incentive programs;
•: Evaluate annually the performance of the Committee; and
•: Review and reassess annually the adequacy of this Charter and recommend any proposed changes to the Board for approval.

Composition and Qualifications

The Committee shall be comprised of such number of directors, as shall be determined yearly by resolution of the Board at its annual meeting following the Annual Meeting of Shareholders. Committee members will be appointed on an annual basis at the annual directors meeting to serve until the next such annual meeting or their earlier demise, resignation or removal. Committee members shall serve at the pleasure of the Board and may be removed at any time. Each Committee member shall meet the independence requirements of the New York Stock Exchange and any additional legal requirements as shall from time to time be in effect. The Board shall, in the

exercise of business judgment, determine the "independence" of directors for this purpose. The Senior Vice President of Human Resources will serve as the management liaison to the Committee.

The Chairman of the Committee shall be designated by the Chairman of the Board of Directors and approved by a majority vote of the entire Board.

Vacancies on the Committee shall be filled by a majority vote of the entire Board. By a majority vote of the entire Board, a member of the Committee may be removed.

In selecting members of the Committee from time to time, the Board shall consider such qualifications for membership as prior service on the Committee or a compensation committee of another public company or service with a public company which involved executive compensation matters.

The Chairman of the Committee shall be responsible for the orientation of new members regarding compensation matters.

Structure and Operation

The Committee shall meet in person or telephonically, at least four times each year and hold such other meetings from time to time as may be called by its Chairman, with further meetings to occur, or actions to be taken by unanimous written consent, when deemed necessary or desirable by the Committee or its Chairman.

The Committee shall meet in executive session without the presence of any member of management as often as it deems necessary or appropriate.

A majority of the members of the Committee shall constitute a quorum. A majority of the members in attendance shall decide any question brought before any meeting of the Committee.

The Committee may form and delegate authority to subcommittees when appropriate.

The Committee shall keep minutes of its proceedings that shall be signed by such person as designated by the Chairman of the Committee to act as secretary of the meeting. The minutes of the Committee shall be approved by the Committee at its next meeting; available for review by the entire Board; and filed as permanent records with the Corporate Secretary.

The Committee may request that any directors, officers or employees of the Company, or other persons whose advice and counsel are sought by the Committee, attend any meeting of the Committee to provide such pertinent information as the Committee deems necessary or appropriate. The Committee shall have the sole authority to retain and terminate any consulting firm being used to assist in the evaluation of director, Chief Executive or senior executive compensation, including sole authority to approve the firm's fees and other retention terms.

The Chairman of the Committee shall report to the Board, at each meeting of the Board following a meeting of the Committee, the deliberations, actions and recommendations of the Committee.

PERFORMANCE GRAPH

The line graph on the following page compares the cumulative total shareholder return of SCANA assuming reinvestment of dividends with that of the peer group, the S&P Utilities and the S&P 500. SCANA's TSR is measured against an index of the peer group to determine whether performance goals have been met. This group was adjusted from last year to reflect name changes, and changes resulting from mergers and acquisitions and companies no longer meeting the standards required for inclusion in the peer group. The peer group index was prepared by Hewitt Associates, a compensation and benefits consulting company. The index consists of SCANA and the following 61 companies:

Allegheny Energy, Inc.
Allete
Alliant Energy Corporation
Ameren Corp.
American Electric Power Co., Inc.
Aquila, Inc.
Avista Corporation
Black Hills Corp.
Centerpoint Energy, Inc.
Central Vermont Public Service Corp.
CH Energy Group Inc.
CINergy Corp.
Citizens Communications Co.
CLECO Corp.
CMS Energy Corp.
Consolidated Edison, Inc.
Constellation Energy Corp.
Dominion Resources, Inc.
DPL, Inc.
DQE, Inc.
DTE Energy Co.
Duke Energy Corp.
Edison International
El Paso Electric Co.
Empire District Electric Co.
Energy East Corporation
Entergy Corp.
Exelon Corp.
FirstEnergy Corp.
FPL Group, Inc.
Great Plains Energy
Green Mountain Power Corp.
Hawaiian Electric Industries, Inc.
IDACORP, Inc.
MGE Energy, Inc.
Nisource, Inc.
Northeast Utilities
Northwestern Corporation
NSTAR
OGE Energy Corp.
Otter Tail Power Co.
PG&E Corp.
Pepco Holdings, Inc.
Pinnacle West Capital Corp.
PNM Resources Inc.
PPL Corporation
Progress Energy, Inc.
Public Service Enterprise Group, Inc.
Puget Sound Energy, Inc.
Sierra Pacific Resources
Southern Company
TECO Energy, Inc.
TXU Corp.
UIL Holdings Corp.
UniSource Energy Corp.
UNITIL Corp.
Vectren Corporation
Westar Energy, Inc.
Wisconsin Energy Corp.
WPS Resources Corp.
Xcel Energy Inc.

SCANA Corporation
Comparison of Five-Year Cumulative Total Return*
SCANA Corporation, Peer Group,
S&P Utilities and S&P 500

Assumes $100 invested on December 31, 1997, in SCANA Corporation Common Stock, the Peer Group and the S&P Indices.

*Total return assumes reinvestment of dividends.

AUDIT COMMITTEE REPORT

Effective on March 7, 2003, the Board of Directors adopted a new Audit Committee Charter. The new Charter appears on page 26. Under the new Charter, the Audit Committee is responsible for, among other things, the appointment of the external auditors, reviewing with the 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 external auditors. Under the rules of the New York Stock Exchange, all members of the Audit Committee are independent.

In connection with the December 31, 2002 financial statements, the Audit Committee (i) reviewed and discussed the audited financial statements with management; (ii) discussed with the auditors the matters required by Statement on Auditing Standards No. 61; (iii) received and discussed with the auditors matters required by Independence Standards Board Statement No. 1; and (iv) considered the compatibility of non-audit services with the external auditor's independence. Based upon these reviews and discussions, the Audit Committee recommended to the Board of Directors, and the Board of Directors approved, that SCANA's audited financial statements be included in the Securities and Exchange Commission Annual Report on Form 10-K for the fiscal year ended December 31, 2002.

THE AUDIT COMMITTEE

Elaine T. Freeman, Chairman
James A. Bennett
D. Maybank Hagood
Harold C. Stowe
G. Smedes York

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.

PROPOSAL 2 — APPROVAL OF APPOINTMENT OF EXTERNAL AUDITORS

The shares represented by your proxy will be voted (unless you indicate to the contrary) to approve the selection of Deloitte & Touche LLP as independent public accountants to examine SCANA's 2003 financial statements. Deloitte & Touche LLP examined 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 respond to appropriate questions from shareholders.

The new 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 external auditors. Pursuant to a policy adopted by the Audit Committee, the Committee Chairman may pre-approve the rendering of services on behalf of the Audit Committee.

Accounting Fees

The following table sets forth the aggregate fees billed to SCANA Corporation and subsidiaries for the fiscal years ended December 31, 2001 and 2002 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates. SCANA has elected to disclose these fees in accordance with newly adopted Securities and Exchange Commission rules amending the categories of fees required to be disclosed. Certain amounts for 2001 have been reclassified to conform to the 2002 presentation.

	2002		2001
Audit Fees	$	1,567,537	$	1,713,535
Audit Related Fees⁽¹⁾		105,383		96,512
Tax Fees⁽²⁾		64,492		143,244
All Other Fees⁽³⁾		118,958		191,818

Total Fees	$	1,856,370	$	2,145,109

(1): Includes employee benefit plan and subsidiary audits.
(2): Includes tax compliance and tax planning advisory services.
(3): Includes depreciation studies in 2002 and arbitration support services in 2001.

AUDIT COMMITTEE CHARTER

Organization

SCANA Corporation ("SCANA") shall have a committee of the Board of Directors (the "Board") to be known as the Audit Committee (the "Committee"). The Committee shall be comprised of three or more directors as shall be determined yearly by resolution of the Board at its regularly scheduled meeting following the Annual Meeting of Shareholders. Committee members will be appointed on an annual basis at this meeting to serve until the next such meeting or their earlier demise, resignation or removal. Committee members shall serve at the pleasure of the Board and may be removed at any time. Each Committee member shall meet the requirements of the New York Stock Exchange (the "NYSE") and any additional legal requirements applicable to SCANA as shall from time to time be in effect. The Board shall, in the exercise of business judgment, determine the "independence" and "experience" of directors for this purpose.

The Chairman of the Committee shall be designated by the Chairman of the Board and approved by a majority vote of the entire Board.

Vacancies on the Committee shall be filled by a majority vote of the entire Board. A member of the Committee may be removed by a majority vote of the entire Board.

Purpose

The purposes of the Committee are:

to assist Board oversight of

•: the integrity of SCANA's financial statements,
•: SCANA's compliance with legal and regulatory requirements,
•: the external auditors' qualifications and independence,
•: the performance of SCANA's internal audit function ("Audit Services") and external auditors, and
•: SCANA's system of disclosure controls and system of internal controls regarding finance, accounting, legal compliance, and ethics that management and the Board have established;

to prepare the Committee report which the Securities and Exchange Commission (the "SEC") requires in SCANA's annual proxy statement; and

to constitute the Qualified Legal Compliance Committee (the "QLCC"), as defined in SEC Final Rule: Implementation of Standards of Professional Conduct for Attorneys; 17 CFR Part 205.2(k) at www.sec.gov/rules/final/33-8185.htm

Duties, Responsibilities and Authority

In order to carry out the purpose for which it was formed, the Committee shall have the following duties, responsibilities and authority and such other duties as may from time to time be assigned to it by the Board:

General

The Committee will:

•: Require any officer or employee of SCANA or any of its subsidiaries or SCANA's counsel or external auditors to attend any meeting of the Committee or to meet with members of, or consultants to, the Committee when appropriate;

•: Obtain advice and assistance from outside legal, accounting or other advisors, as deemed appropriate, to perform its duties and responsibilities and authorize appropriate compensation for such advisors;
•: Exercise all the authority and discharge all the duties of the QLCC;
•: Prepare the report of the Committee to be included in SCANA's annual proxy statement;
•: Review (a) major issues regarding accounting principles and financial statement preparation, any changes in SCANA's selection or application of accounting principles, any major issues as to the adequacy of SCANA's internal controls and any special audit steps adopted in light of material control deficiencies; (b) analyses prepared by management and/or the external auditors setting forth financial reporting issues and judgments made in connection with the preparation of the financial statements, including the analysis of the use of alternate Generally Accepted Accounting Principles ("GAAP") methods and their effects on the financial statements; (c) the effect of regulatory and accounting initiatives, as well as off-balance sheet structures, on the financial statements; and (d) earnings press releases and the financial information used as the basis for earnings guidance and briefings to analysts and rating agencies;
•: Review with the external auditors and Audit Services the adequacy and effectiveness of SCANA's internal controls, and request recommendations for improvement;
•: Meet periodically and separately, with management, Audit Services, the external auditors, the Corporate Compliance and Internal Auditing Officer and the Risk Management Officer;
•: Report regularly to the Board of Directors on Committee actions fulfilling its responsibilities as stated in this Charter;
•: Review with the Board any issues that arise with respect to the quality or integrity of SCANA's financial statements, its compliance with legal or regulatory requirements, the performance and independence of its external auditors or the performance of Audit Services;
•: Meet four times a year or more frequently as circumstances, the NYSE or laws may require;
•: Delegate authority to individuals or subcommittees as appropriate;
•: Submit the minutes of all meetings of the Committee to the Board of Directors;
•: Provide annual written affirmation to the Board and the NYSE on the independence and experience of Committee members, using NYSE guidelines. The Committee will disclose to the Board any changes in a member's status regarding independence. In the event of any such change, the Board will review and determine whether the director will continue to serve on the Committee;
•: Review and reassess annually the adequacy of the Committee's Charter and of its own performance;
•: Recommend any proposed changes in the Charter to the Board for approval and disclose such changes in the proxy statement when they are approved;
•: Require publication of the Charter in the proxy statement every three years;
•: Review reports and disclosures of insider and affiliated party transactions;
•: Review with the General Counsel, legal matters that may have a material impact on the financial statements or SCANA's compliance policies;
•: Set SCANA's hiring policy regarding the employment of current or former employees of SCANA's external auditors.

With Respect to the External Auditor and Financial Statement Disclosures

The Committee will:

•: Appoint or replace the external auditors subject to shareholder ratification;
•: Exercise oversight of the work of the external auditors (including resolution of disagreements between management and the external auditors regarding financial reporting) for the purpose of preparing or issuing an audit report or related work;
•: Set compensation of the external auditors who shall report directly to the Committee;
•: Pre-approve all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed by the external auditors;
•: Review with management and the external auditors the annual audited financial statements including the disclosures to be made under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and recommend to the Board the inclusion of the audited financial statements in the Form 10-K, if appropriate;
•: Review with management and the external auditors the quarterly financial statements including disclosures to be made under "Management's Discussion and Analysis of Financial Condition and Results of Operations" prior to the filing of each Form 10-Q, including the results of the external auditors' review of the quarterly financial statements;
•: Meet with the external auditors to review and approve the plan and scope of each year's audit;
•: Meet with the external auditors to discuss the role and sufficiency of Audit Services;
•: Review with the external auditors the matters required by applicable professional and auditing standards relating to the conduct of the audit, including (a) the adoption of, or changes to, SCANA's auditing and accounting principles and practices as suggested by the external auditors, Audit Services or management, (b) the management letter provided by the external auditors and SCANA's response to that letter, and (c) any difficulties encountered in the course of the audit work, including any restrictions on the scope of activities or access to requested information, and any disagreements with management;
•: Review with management and the external auditors financial reporting issues and judgments made in connection with the preparation of SCANA's financial statements, including any changes in SCANA's selection or application of accounting principles, any major issues as to the adequacy of SCANA's internal controls, the development, selection and disclosures of critical accounting estimates and analyses of the effect of alternative assumptions, estimates or GAAP methods on SCANA's financial statements;
•: Review for adequacy, management's response to areas needing attention for additional controls or procedures previously brought to management's attention by the external auditors;
•: Evaluate the external auditors' qualifications, performance and independence, including a review of the lead audit partner;
•: Review with the Board the independence and performance of the external auditors;
•: Review all reports required to be submitted by the external auditors to the Committee under Section 10A of the Securities Exchange Act of 1934, which requires that the external auditors inform the Committee of illegal acts that have been detected or otherwise come to the attention of the external auditors in the course of the audit;
•: Review the rotation of audit personnel and external auditors;

•: Obtain and review an annual report by the external auditors describing the firm's internal quality-control procedures, any material issues raised by the most recent internal quality-control review, or peer review, of the firm, and all relationships between the external auditors and SCANA to assess the auditors' independence.

Relationship with SCANA's Audit Services

The Committee will:

•: Review the internal audit plan annually with the Corporate Compliance and Internal Auditing Officer and the General Auditor;
•: Review Audit Services' responsibilities, budget and staffing with the Corporate Compliance and Internal Auditing Officer and the General Auditor;
•: Require Audit Services to provide a summary of observations of completed internal audits and a progress report on the audit plan prior to each Committee meeting;
•: Require reports on follow-up from previous recommendations;
•: Review any scope restrictions placed on Audit Services by management;
•: Review the appointment, replacement, reassignment, or dismissal of the General Auditor.

Relationship with Corporate Compliance

The Committee will:

•: Require reports from the Corporate Compliance and Internal Auditing Officer regarding SCANA's conformity with applicable legal requirements and its Code(s) of Conduct;
•: Establish procedures for the receipt, retention and treatment of complaints received by SCANA regarding accounting, internal accounting controls or auditing matters and the confidential, anonymous submission by employees of concerns regarding questionable accounting or auditing matters;
•: Review annually SCANA's Code(s) of Conduct and make recommendations;
•: Require updates from the Corporate Compliance Officer concerning ongoing employee training and compliance;
•: Review the appointment, replacement, reassignment, or dismissal of the Corporate Compliance and Internal Auditing Officer.

Relationship with Risk Management

The Committee will:

•: Review annually SCANA's Corporate Risk Management program, its scope and effectiveness;
•: Require regular reports measuring corporate risks;
•: Review the appointment, replacement, reassignment, or dismissal of the Corporate Risk Management Officer.

Relationship with Management

The Committee will:

•: Review with management all matters related to financial disclosures, internal controls, legal compliance and business risks of SCANA.

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 our 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 us, all filings on behalf of such persons were made on a timely basis in 2002. Mr. Hagood filed late his reports on Form 5 for 2000 and 2002 with respect to a total of approximately 30 shares he acquired through the reinvestment of dividends in his brokerage account.

Shareholder Proposals and Recommendations for a Director Nominee

Any shareholder may recommend to the Executive Committee, persons for nomination for director, by writing to the Corporate Secretary, 1426 Main Street, Columbia, South Carolina 29201.

In order to be considered for inclusion in SCANA's Proxy Statement and Proxy Card for its 2004 Annual Meeting of Shareholders, a shareholder proposal must be received at the principal office of SCANA Corporation, 1426 Main Street, Columbia, South Carolina 29201, by November 18, 2003. 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 2004 Annual Meeting of Shareholders must notify SCANA no later than November 18, 2003 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., 111 Commerce Road, Carlstadt, New Jersey 07072, to assist in the solicitation of proxies for the 2003 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 telegraph, 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, 2003 and bring proof of identification or, if you hold your shares through a stockbroker or other nominee, you 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, 2003.

Availability of Form 10-K

A copy of SCANA's Annual Report on Form 10-K for the fiscal year ended December 31, 2002, 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 receipt by the Company of a written request from such shareholder. The exhibits to the Form 10-K will also be provided upon request and payment of copying charges. Requests for the Form 10-K should be directed to:

H. John Winn III
Manager-Investor Relations and
Shareholder Services
SCANA Corporation
1426 Main Street (054)
Columbia, South Carolina 29201

SCANA CORPORATION

Lynn M. Williams
Secretary
March 17, 2003

APPENDIX

Annual Financial Statements, Management's Discussion and Analysis and Other Company Information:
	Selected Financial and Other Statistical Data	A-2
	SCANA's Business	A-3
	Management's Discussion and Analysis of Financial Condition and Results of Operations	A-5
	Quantitative and Qualitative Disclosures about Market Risk	A-28
	Independent Auditors' Report	A-31
	Consolidated Balance Sheets	A-32
	Consolidated Statements of Operations	A-34
	Consolidated Statements of Cash Flows	A-35
	Consolidated Statements of Capitalization	A-36
	Consolidated Statements of Comprehensive Income (Loss) and Changes in Common Equity	A-38
	Notes to Consolidated Financial Statements	A-39
	Market for Registrant's Common Equity and Related Shareholder Matters	A-66
	Executive Officers	A-67

A-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,			2002		2001	2000	1999	1998
Statement of Income Data
	Operating Revenues		$2,954		$3,451	$3,433	$2,078	$2,106
	Operating Income		514		528	554	353	470
	Other Income (Expense)		(180	)	550	44	90	19
	Income Before Cumulative Effect of Accounting Change		88		539	221	179	223
	Net Income (Loss)		(142	)	539	250	179	223
Common Stock Data
	Weighted Average Number of Common Shares Outstanding (Millions)		106.0		104.7	104.5	103.6	105.3
	Basic and Diluted Earnings (Loss) Per Share		$(1.34	)	$5.15	$2.40	$1.73	$2.12
	Dividends Declared Per Share of Common Stock		$1.30		$1.20	$1.15	$1.32	$1.54
Balance Sheet Data
	Utility Plant, Net		$5,474		$5,263	$4,949	$3,851	$3,787
	Total Assets		7,754		7,822	7,427	6,011	5,281
	Capitalization:
		Common equity	$2,177		$2,194	$2,032	$2,099	$1,746
		Preferred Stock (Not subject to purchase or sinking funds)	106		106	106	106	106
		Preferred Stock, net (Subject to purchase or sinking funds)	9		10	10	11	11
		SCE&G — Obligated Mandatorily Redeemable Preferred Securities of SCE&G's Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount of the 7.55% Junior Subordinated Debentures of SCE&G, due 2027	50		50	50	50	50
		Long-term Debt, net	2,834		2,646	2,850	1,563	1,623

	Total Capitalization		$5,176		$5,006	$5,048	$3,829	$3,536

Other Statistics⁽¹⁾
	Electric:
		Customers (Year-End)	560,224		547,388	537,253	523,552	517,447
		Total sales (Million KWh)	23,085		22,928	23,352	21,744	21,203
		Generating capability — Net MW (Year-End)	4,866		4,520	4,544	4,483	4,387
		Territorial peak demand — Net MW	4,404		4,196	4,211	4,158	3,935
	Regulated Gas:
		Customers (Year-End)	666,868		645,749	637,018	260,456	257,051
		Sales, excluding transportation (Thousand Therms)	1,356,039		1,183,463	1,389,975	1,013,083	1,002,952
	Retail Gas Marketing:
		Retail customers (Year-End)	374,347		385,581	431,814	430,950	78,091
		Firm customer deliveries (Thousand Therms)	337,858		359,602	431,115	229,660	4,692
	Nonregulated interruptible customer deliveries (Thousand Therms)⁽²⁾		514,731		407,188	306,099	188,828	2,167,931

(1): Other Statistics for 2000 exclude the effect of the change in accounting for unbilled revenues, where applicable.
(2): Interruptible deliveries for 1998 includes volumes from the Houston office of SCANA Energy Marketing, Inc., which was closed in 1999.

Other significant events affecting historical earnings trends include the following:

In 2002 SCANA Corporation (SCANA) recorded impairment losses on its investments in Deutsche Telekom AG (DTAG) of $182 million or $1.72 per share and ITC^DeltaCom, Inc. 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 for the acquisition adjustment associated with Public Service Company of North Carolina, Incorporated (PSNC Energy). 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.

Effective January 1, 2000, SCANA acquired PSNC Energy, which increased earnings by $21 million or $.20 per share, exclusive of interest costs on acquisition debt.

In 1999 SCANA sold its propane businesses, recognizing a gain of $30 million or $.29 per share, and sold telecommunications towers, recognizing a gain of $4.8 million or $.05 per share.

A-2

SCANA'S BUSINESS

SCANA Corporation (SCANA) is a public utility holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), which has 12 direct, wholly owned subsidiaries (collectively, the Company) that are engaged in the functionally distinct operations described below. SCANA also has an investment in one limited liability company (LLC) which owns and operates a cogeneration facility in Charleston, South Carolina. SCANA also has three other direct, wholly owned subsidiaries that are in liquidation.

Regulated Utilities

South Carolina Electric & Gas Company (SCE&G) is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity and in the purchase and sale, primarily at retail, of natural gas. SCE&G's electric service area extends into 24 counties covering more than 15,000 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 approximately 2.7 million. 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.

Until October 2002 SCE&G operated a transit system in Columbia, South Carolina. In October 2002 the transit system was transferred to the City of Columbia, South Carolina.

South Carolina Generating Company, Inc. (GENCO) owns and operates an electric power plant and sells electricity solely to SCE&G. South Carolina Fuel Company, Inc. (Fuel Company) acquires, owns and provides financing for SCE&G's nuclear fuel, fossil fuel and sulfur dioxide emission allowance requirements.

Public Service Company of North Carolina, Incorporated (PSNC Energy) is a public utility engaged primarily in purchasing, selling and transporting natural gas to approximately 384,000 residential, commercial and industrial customers. PSNC Energy provides service to 27 of 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 and directly to industrial customers in 40 counties throughout South Carolina. SCPC owns liquefied natural gas (LNG) liquefaction and storage facilities. It also supplies the natural gas for SCE&G's gas distribution system. Other resale customers include municipalities and county gas authorities and gas utilities.

SCG Pipeline, Inc. (SCG), when operational, will provide interstate transportation services for natural gas to markets in southeastern Georgia and South Carolina. SCG will transport natural gas from interconnections with Southern Natural Gas Company (Southern Natural) at Port Wentworth, Georgia, and from an import terminal owned by Southern LNG, Inc. (Southern LNG) at Elba Island, near Savannah, Georgia. In September 2002 SCG received approval from the Federal Energy Regulatory Commission (FERC) to acquire an interest in an existing pipeline and to build a pipeline from Elba Island, Georgia to Jasper County, South Carolina. The endpoint of SCG's line will be at the site of the natural gas-fired generating station that SCE&G is building in Jasper County. Construction of the pipeline is expected to begin in the first half of 2003, with completion expected in the fall of 2003.

A-3

Nonregulated Businesses

SCANA Energy Marketing, Inc. (SEMI) markets natural gas and wholesale electricity primarily in the southeast and provides energy-related risk management services to producers and customers. In addition, SCANA Energy, a division of SEMI, markets natural gas to approximately 374,000 customers (as of December 31, 2002) in Georgia's natural gas market.

SCANA Communications, Inc. (SCI) owns and operates a 500-mile fiber optic telecommunications network in South Carolina and, through its affiliation with FRC, LLC, has an interest in an additional 400 miles in South Carolina and North Carolina. SCI also provides tower site construction, management and rental services in South Carolina and North Carolina. SCI owned an 800 Mhz radio service network within South Carolina which was sold to Motorola, Inc. in April 2002.

SCANA Communications Holdings, Inc. (SCH), a Delaware corporation and a wholly owned subsidiary of SCI, holds investments in ITC Holding Company, Inc. (ITC Holding), ITC^DeltaCom, Inc. (ITC^DeltaCom), and Knology, Inc. (Knology), which are telecommunications services companies operating in the southeastern United States. In December 2002, SCH completed the sale of its investment in DeutscheTelekom AG (DTAG), an international telecommunications carrier.

ServiceCare, Inc. is engaged primarily in providing homeowners with energy-related products and 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 an alternate fuel facility owned by non-affiliates, and it receives management fees, royalties and expense reimbursements related to those activities.

SCANA Resources, Inc. conducts energy-related businesses and provides energy-related services.

Service Company

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

A-4

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 the safe harbor provided by 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) changes in the utility and nonutility regulatory environment, (3) changes in the economy, especially in areas served by the Company's subsidiaries, (4) the impact of competition from other energy suppliers, (5) growth opportunities for the Company's regulated and diversified subsidiaries, (6) the results of financing efforts, (7) changes in the Company's accounting policies, (8) weather conditions, especially in areas served by the Company's subsidiaries, (9) performance and marketability of the Company's investments in telecommunications companies, (10) performance of the Company'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 the Company's periodic reports filed with the U.S. Securities and Exchange Commission (SEC). The Company disclaims any obligation to update any forward-looking statements.

COMPETITION

Electric Operations

In South Carolina, electric restructuring efforts remain stalled, and consideration of electric restructuring legislation is unlikely in 2003. Further, while several companies have announced their intent to site merchant generating plants in the Company's service territory, economic events, environmental concerns and other factors have slowed those efforts. In view of the potential for deregulation, the Company has continued efforts to renew franchise agreements with municipalities within its current service area. Effective October 2002, SCE&G secured a 30-year franchise to provide the City of Columbia, South Carolina, with electric and natural gas services. Columbia is one of the largest cities in SCE&G's service area. Previously, SCE&G reached franchise agreements with the cities of North Charleston (franchise expires in 2021), Charleston (franchise expires in 2026) and numerous other municipalities. In addition, in May 2001 SCE&G signed an electric supply contract with North Carolina Electric Membership Corporation to supply 350 megawatts in each of 2004 and 2005 and 250 megawatts annually in 2006 through 2012. These energy sales are recallable for SCE&G's native load, if necessary.

At the federal level, energy legislation passed both houses of Congress in 2002, though significant differences between the House and Senate versions were not reconciled before the legislative session adjourned. Some of the more stringent provisions of this legislation would have required, among other things, that one percent of the electric energy sold by retail electric suppliers, beginning in 2005, escalating to ten percent in 2019, be generated from renewable energy resources. Renewable energy resources, as defined in some versions of the legislation, would have excluded hydroelectric generation. Substantial penalties would have been levied for failure to comply. Electric cooperatives and municipal utilities would have been exempt from these requirements. The Company expects similar

A-5

legislation will be introduced in Congress in 2003. The Company cannot predict whether such legislation will be enacted, and if it is, the conditions it would impose on utilities.

In June 2002 implementation of GridSouth Transco LLC (GridSouth) was suspended pending the issuance and evaluation of new FERC directives. In July 2002 FERC issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design which proposes sweeping changes to the country's existing regulatory framework governing transmission, open access and energy markets and will attempt, in large measure, to standardize the national energy market. While it is anticipated that significant change to the NOPR may occur and that implementation, presently scheduled for September 2004, may be delayed, any rules standardizing the markets may have a significant impact on SCE&G's access to or cost of power for its native load customers and on SCE&G's marketing of power outside its service territory. The Company is currently evaluating this NOPR to determine what effect it will have on SCE&G's operations. Additional directives from FERC are expected in 2003.

Gas Distribution

The Company has secured franchise agreements with several municipalities within its current service areas to provide natural gas services. See previous discussion at Electric Operations. Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, the other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect the price and impact the Company's ability to retain large commercial and industrial customers on a monthly basis.

Gas Transmission

In September 2002 SCG received approval from FERC to acquire an interest in an existing pipeline and to build a pipeline from Elba Island, Georgia to Jasper County, South Carolina. When operational, SCG will provide interstate transportation services for natural gas to markets in southeastern Georgia and South Carolina. SCG will transport natural gas from interconnections with Southern Natural at Port Wentworth, Georgia, and from an import terminal owned by Southern LNG at Elba Island, near Savannah, Georgia. The endpoint of SCG's pipeline will be at the site of the natural gas-fired generating station that SCE&G is building in Jasper County, South Carolina. Construction of the pipeline is expected to begin in the first half of 2003, with completion expected in the fall of 2003.

SCPC supplies natural gas to SCE&G, for its resale to gas distribution customers and for certain electric generation needs. Gas transmission also sells natural gas to large commercial and industrial customers in South Carolina, and it faces the same competitive pressures as gas distribution for these classes of customers.

Retail Gas Marketing

In April 2002 Georgia's Natural Gas Consumer's Relief Act of 2002 (the Act) became law. The Act attempts to resolve many of the consumer protection and other public policy issues surrounding Georgia's natural gas market with the following significant provisions:

•: creates a regulated provider selected through a bidding process to serve low-income and high credit risk customers,
•: allows Georgia's 42 non-profit Electric Membership Corporations (EMCs) to establish natural gas affiliates that may seek certification as marketers of natural gas,
•: establishes new service quality standards and assignment of interstate assets, and
•: grants to the Georgia Public Service Commission (GPSC) the authority to

A-6

temporarily regulate rates if more than 90% of customers in a specific area of the state are served by three or fewer marketers.

In June 2002 SCANA Energy won GPSC approval to become the State's regulated provider. In this capacity, SCANA Energy serves low-income customers generally at below-market rates, subsidized by Georgia's Universal Service Fund, and extends service generally at above-market rates to high credit risk customers who have been denied service by other marketers. SCANA Energy began serving these customers on September 1, 2002, and at December 31, 2002, approximately 11,000 customers were being served by SCANA Energy under this program.

In June 2002 the fourth largest marketer in Georgia's natural gas market declared bankruptcy. In July 2002 a subsidiary of Southern Company completed its purchase of the bankrupt marketer's Georgia operations. Southern Company, through another subsidiary, sells electricity to approximately two million customers in Georgia. In addition, affiliates of two EMCs have been certified by the GPSC as gas marketers. These new entrants to Georgia's natural gas market may help stabilize the market, although it is unclear what impact these entrants may have on the Company's competitive position. At December 31, 2002 the three largest marketers (which include SCANA Energy) served approximately 80% of Georgia's natural gas market.

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 11 of Notes to 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. This factor and others (e.g., the level of bad debts experienced) are, in the aggregate, used to establish retail pricing levels at SCANA Energy. As a result of the regulatory actions discussed above and other downward pricing pressures inherent in the competitive market, SCANA Energy may be unable to sustain its current level of customers and/or pricing, thereby reducing expected margins and profitability.

LIQUIDITY AND CAPITAL RESOURCES

The Company's cash requirements arise primarily from the operational needs of SCANA subsidiaries, the Company's construction program, the investments of SCANA's subsidiaries and payment of dividends. The ability of SCANA's regulated subsidiaries to replace existing plant investment, as well as to expand to meet future demand for electricity and gas, will depend upon their ability to attract the necessary financial capital on reasonable terms. SCANA's 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 the regulated subsidiaries continue their ongoing construction programs, the Company expects to seek increases in rates. The Company's future financial position and results of operations will be affected by the regulated subsidiaries' ability to obtain adequate and timely rate and other regulatory relief, if requested.

In January 2003 the Public Service Commission of South Carolina (SCPSC) issued an order granting SCE&G an increase in retail electric rates of 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, without the approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.

A-7

The estimated primary cash requirements for 2003 and the actual primary cash requirements for 2002, excluding requirements for non-nuclear fuel purchases, short-term borrowings and dividends, are as follows:

(Millions of dollars)		2003		2002
Property additions and construction expenditures, net of AFC		$	838	$	681
Nuclear fuel expenditures			30		13
Investments			20		62
Maturing obligations, redemptions and sinking and purchase fund requirements			374		1,082

	Total	$	1,262	$	1,838

Approximately 28% of total cash requirements was provided from internal sources in 2002 as compared to 41% in 2001.

The Company's contractual cash obligations as of December 31, 2002 are summarized as follows:

Contractual Cash Obligations

December 31, 2002 (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)	$	5,215	$	759	$	1,048	$	409	$	2,999
Preferred stock sinking funds		10		1		2		1		6
Capital leases		3		2		1		—		—
Operating leases		76		16		33		19		8
Other commercial commitments		2,518		1,249		571		173		525

Included in other commercial commitments are estimated obligations under forward contracts for natural gas purchases. Many of these forward contracts for natural gas purchases include customary "make-whole" or default provisions, but are not considered to be "take-or-pay" contracts. Certain of these contracts relate to regulated businesses; therefore, the effects of such contracts on fuel costs are reflected in electric or gas rates. At September 30, 2002, other commercial commitments included amounts for a take-and-pay natural gas contract with a 15 year term beginning in 2004. That contract was terminated in December 2002, and amounts due under the contract totaling $4.2 billion over the 15 year term have been removed from contractual cash obligations. See Note 12E of Notes to Consolidated Financial Statements.

In addition to these commercial commitments, the Company is party to certain New York Mercantile Exchange (NYMEX) futures contracts for which any unfavorable market movements through December 31, 2002 are funded in cash. These derivatives are accounted for as cash flow hedges under Statement of Financial Accounting Standards (SFAS)133, "Accounting for Derivative Instruments and Hedging Activities," as amended, and their effects are reflected within other comprehensive income until such time as the anticipated sales transactions occur.

In addition to the above contractual cash commitments, the Company sponsors a noncontributory defined benefit pension plan and an unfunded health care and life insurance benefit plan for retirees. The pension plan has been adequately funded, with no contributions having been required since 1997. Cash benefit payments under the health care and life insurance benefit plan have been approximately $10 million per year in recent years, and similar payments are expected in the future.

The Company anticipates that its contractual cash obligations will be met through internally generated funds and the incurrence of additional short-term and long-term indebtedness. Sales of additional equity

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securities may also occur. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future.

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 state and federal regulatory bodies including state public service commissions and the SEC. The following describes the financing programs currently utilized by the Company.

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.

At December 31, 2002 SCANA had $163 million of unused lines of credit, comprised of $50 million of committed lines, expiring in 2003, and $113 million of uncommitted lines. There were no amounts outstanding under SCANA's lines of credit at December 31, 2002 and 2001. On January 3, 2003 SCANA obtained an additional $50 million committed line of credit, expiring in 2004. On January 8, 2003, SCANA renegotiated an existing $78 million uncommitted line of credit to allow SCE&G to share in this line of credit.

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 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.

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.

SCE&G's First and Refunding Mortgage Bond Indenture, dated April 1, 1945 (Old Mortgage), contains provisions prohibiting the issuance of additional bonds thereunder (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 the annual interest requirements on all Class A Bonds to be outstanding (Bond Ratio). For the year ended December 31, 2002 the Bond Ratio was 5.51. 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 totaled approximately $522 million at December 31, 2002), (ii) retirements of Class A Bonds (which retirement credits totaled $187.2 million at December 31, 2002), 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, 2002 approximately $1.3 billion 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 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, 2002 the New Bond Ratio was 5.36.

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

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(as defined therein) for the 12 consecutive months immediately preceding the month of issuance are at least one and one-half 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, 2002, the Preferred Stock Ratio was 1.72.

The Articles also require the consent of at least 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, 2002 the ten percent test would have limited issuances of unsecured indebtedness to approximately $366.7 million. Unsecured indebtedness at December 31, 2002 totaled approximately $127.6 million.

At December 31, 2002 SCE&G had $250 million of unused committed lines of credit comprised of $175 million expiring in 2003 and $75 million expiring in 2005. These lines of credit support the issuance of commercial paper. SCE&G's commercial paper outstanding totaled $127.6 million and $114.7 million at December 31, 2002 and 2001, respectively, at weighted average interest rates of 1.40% and 1.95%, respectively. On January 8, 2003 a credit agreement was reached allowing SCE&G to share an existing $78 million SCANA uncommitted line of credit. In addition, Fuel Company has a credit agreement for a maximum of $125 million expiring in 2003 with the full amount available at December 31, 2002. The credit agreement supports the issuance of short-term commercial paper for the financing of nuclear and fossil fuels and sulfur dioxide emission allowances. Fuel Company commercial paper outstanding totaled $50.1 million at December 31, 2002 and 2001, at weighted average interest rates of 1.38% and 2.06%, respectively. This commercial paper and amounts outstanding under the revolving credit agreement, if any, are guaranteed by SCE&G.

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 customary approvals discussed above, the Indenture under which they are issued contains no specific limit on the amount which may be issued. PSNC Energy expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future.

At December 31, 2002 PSNC Energy had $125 million unused committed lines of credit, expiring in 2003, under a credit agreement supporting the issuance of commercial paper. PSNC Energy had total commercial paper outstanding of $31.1 million at December 31, 2002, at a weighted average interest rate of 1.42%. PSNC Energy had no commercial paper outstanding at December 31, 2001.

Financing Transactions

The following financing transactions have occurred since January 1, 2002:

•: On January 31, 2002 SCANA issued $250 million of medium-term notes maturing February 1, 2012 and bearing a fixed interest rate of 6.25%. Also on January 31, 2002 SCANA issued $150 million of two-year floating rate notes maturing February 1, 2004. The interest rate on the floating rate notes is reset quarterly based on three-month LIBOR plus 62.5 basis points. Proceeds from these issuances were used to refinance $400 million of two-year floating rate notes that matured February 8, 2002, which had been issued to finance SCANA's acquisition of PSNC Energy.
•: On January 31, 2002 SCE&G issued $300 million of first mortgage bonds having an annual interest rate of 6.625% and maturing February 1, 2032. The proceeds from the sale of these bonds were used to reduce short-term debt primarily incurred as a

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result of SCE&G's construction program and to redeem on March 11, 2002 its $103.5 million First and Refunding Mortgage Bonds, 8⁷/8% Series due August 15, 2021.

•: On April 24, 2002 SCANA redeemed $202 million of floating rate medium-term notes that were set to mature January 24, 2003. The notes were bearing interest at a rate of 2.90% when redeemed.
•: On July 15, 2002 SCANA retired at maturity $300 million of floating rate medium-term notes. The notes were bearing interest at a rate of 4.063% at maturity.
•: On August 15, 2002 SCANA issued $100 million one-year floating rate medium-term notes maturing August 15, 2003. The interest rate on the notes is reset quarterly based on three-month LIBOR plus 87.5 basis points. The proceeds were used for general corporate purposes.
•: On October 16, 2002 SCANA sold 6 million shares of common stock and received net proceeds of approximately $146 million. On October 17, 2002 SCANA made an equity contribution to SCE&G of $150 million.
•: On November 8, 2002 the South Carolina Jobs — Economic Development Authority (JEDA) issued, and SCE&G borrowed the proceeds of, an aggregate of $90.4 million principal amount of tax exempt industrial revenue bonds (the Bonds). The Bonds bear interest at rates ranging from 4.2% to 5.45%, with maturities ranging from 2012 to 2032. Proceeds from the Bonds were used to refund an aggregate amount of $62.3 million principal amount of pollution control revenue bonds and to pay the costs of solid waste disposal facilities at two of SCE&G's electric generating plants.
•: On January 23, 2003 SCE&G issued $200 million First Mortgage Bonds having an annual interest rate of 5.80% and maturing on January 15, 2033. The proceeds from the sale of these bonds were used to reduce short-term debt and for general corporate purposes.
•: The Company received payments to terminate swaps totaling $29.3 million and $6.5 million in 2002 and 2001, respectively. These amounts are being amortized over the ten year term of the underlying debt they formerly hedged. At December 31, 2002 the estimated fair value of the Company's swaps totaled $9.0 million related to combined notional amounts of $344.9 million.

Other Information

SCE&G placed in service a $264 million gas turbine generator project in Aiken County, South Carolina in June 2002. Two combined-cycle turbines burn natural gas to produce 341 megawatts of new electric generation and use exhaust heat to replace a coal-fired steam boiler that had powered two existing 75 megawatt turbines at the Urquhart Generating Station.

In May 2002 SCE&G began construction of an 875 megawatt generation facility in Jasper County, South Carolina, to supply electricity to its South Carolina customers. The facility will include three natural gas combustion-turbine generators and one steam-turbine generator. The $450 million facility is expected to begin commercial operation in mid-2004. SCG will transport natural gas to the facility.

In October 1999 FERC mandated that SCE&G reinforce its Lake Murray dam in order to comply with new federal safety standards and maintain the lake in case of an extreme earthquake. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost approximately $275 million and be completed in 2005. Costs incurred through December 31, 2002 totaled approximately $67 million.

In 2002 SCE&G entered into an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the above Lake Murray dam remediation project. The loan agreement provides for interest-free borrowings for costs incurred not to exceed $59 million, with such borrowings being repaid over ten years from the

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initial borrowing. At December 31, 2002 SCE&G had not yet borrowed under the agreement.

ENVIRONMENTAL MATTERS

Electric Operations

The Clean Air Act Amendments of 1990 (CAA) required electric utilities to reduce emissions of sulfur dioxide and nitrogen oxides (NOx) substantially by the year 2000. The Company remains in compliance with these requirements. In 1998 the United States Environmental Protection Agency (EPA) required the State of South Carolina, among other states, to modify its state implementation plan (SIP) to address the issue of NOx pollution. The State's SIP requires additional emissions reductions in 2004 and beyond. Further, the EPA has indicated that it will propose regulations by December 2003 for stricter limits on mercury and other toxic pollutants generated by coal-fired plants. To comply with these state and federal regulations, SCE&G and GENCO expect to incur capital expenditures of approximately $131 million over the 2003-2007 period to retrofit existing facilities, with increased operation and maintenance costs of approximately $1.8 million per year. To meet compliance requirements for the years 2008 through 2012, the Company anticipates additional capital expenditures of approximately $125 million.

The EPA has undertaken an aggressive enforcement initiative against the utilities industry, and the Department of Justice has brought suit against a number of utilities in federal court alleging violations of the CAA. 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 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). The Company and SCE&G 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. 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. The regulations also provide an exemption for an increase in emissions resulting from increased hours of operation or production rate and from demand growth. It is possible that the EPA will commence enforcement actions against SCE&G, 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 assertions relative to the Company's and SCE&G's compliance with the CAA would be without merit. However, if successful, such assertions could have a material adverse effect on the Company's financial position, cash flows and results of operations.

The Clean Water Act, as amended, provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under this 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 thermal discharges and strategies for toxicity reduction in wastewater streams. The Company is developing compliance plans for these initiatives. Congress is expected to consider further amendments to the Clean Water Act in 2003. Such legislation may include limitations to mixing zones, the implementation of technology-based standards for main condenser cooling water including intake and discharge structures and toxicity-based standards. These provisions, if passed, could have a material impact on the results of operations and cash flows of SCE&G and GENCO.

Gas Distribution

The Company maintains an environmental assessment program to identify and evaluate

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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 expenditures could 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 $17.9 million and $24.4 million at December 31, 2002 and 2001, 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 benzene contamination in the intermediate aquifer on surrounding properties. SCE&G anticipates that the remaining remediation activities will be completed in 2003, with certain monitoring and retreatment activities continuing until 2007. As of December 31, 2002, SCE&G has spent approximately $18.4 million to remediate the Calhoun Park site. Total remediation costs are estimated to be $21.9 million.
•: SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by DHEC. SCE&G is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. SCE&G anticipates that major remediation activities for these three sites will be completed before 2006. SCE&G has spent approximately $2.2 million related to these sites, and expects to incur an additional $5.9 million.

In addition, PSNC Energy owns, or has owned, all or portions of seven sites in North Carolina on which MGPs were formerly operated. Intrusive investigation (including drilling, sampling and analysis) has begun at two sites and the remaining sites have been evaluated using historical records and observations of current site conditions. These evaluations have revealed that MGP residuals are present or suspected at several of the sites. 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 potentially responsible parties (PRP). In September 2002 an allocation agreement was reached relieving PSNC Energy of liability for two of the seven sites. PSNC Energy has recorded a liability and associated regulatory asset of $7.8 million, which reflects the estimated remaining liability at December 31, 2002. Amounts incurred to date that have not been recovered through gas rates are approximately $1.2 million. Management believes that all MGP cleanup costs incurred will be recoverable through gas rates.

REGULATORY MATTERS — STATE

Regulated public utilities are allowed to record as assets some costs that would be expensed by other enterprises. If deregulation or other changes in the regulatory environment occur, the Company may no longer be eligible to apply this accounting treatment and may be required to eliminate such regulatory assets from its balance sheet. Although the potential effects of deregulation cannot be determined at present, discontinuation of the accounting treatment could have a material adverse effect on the Company's results of operations in the period the write-off would be recorded. It is expected that cash flows and the financial position of the Company would not be materially affected by the discontinuation of the accounting treatment. The Company reported approximately $296 million and $114 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities of approximately $137 million and $43 million, respectively, on its balance sheet at December 31, 2002.

The Company's generation assets would be exposed to considerable financial risks in a

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deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, the Company could be required to write down its investment in these 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, 2002 the Company's net investment in fossil and hydro and nuclear generation assets was approximately $1,921 million and $546 million, respectively.

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.

Electric

In January 2003 the SCPSC issued an order granting SCE&G an increase in retail electric rates of 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, without the approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.

On December 31, 2002 the SCPSC issued an order approving SCE&G's request to capitalize the cost of fuel consumed in the production of test power for the gas turbines installed at Urquhart Generating Station in 2002. As a result, SCE&G transferred approximately $12.5 million from fuel used in electric generation to electric utility plant.

In May 2002 the SCPSC issued an order approving SCE&G's request to increase the fuel component of rates charged to electric customers from 1.579 cents per KWh to 1.722 cents per KWh. The increase reflects higher fuel costs projected for the period May 2002 through April 2003. The increase also provided continued recovery for under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of SCE&G's base load generating plants in winter 2000-2001. The new rates were effective as of the first billing cycle in May 2002. In January 2003 in conjunction with the approval of the retail rate increase, the SCPSC approved SCE&G's request to reduce the fuel component to 1.678 cents per KWh.

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 the years ended December 31, 2002 and 2001 was as follows:

Rate Per Therm		Effective Date
$.993		January-February 2001
$.793		March-October 2001
$.596		November 2001-October 2002
$.728		November-December 2002

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In March 2003 the SCPSC issued an order approving SCE&G's request for an out-of-period adjustment to increase the cost of gas component of its rates for natural gas service from $.728 per therm to $.928 per therm, effective with the first billing cycle in March 2003.

In 1994 the SCPSC issued an order approving SCE&G's request to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former MGPs. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for SCE&G's gas operations that had previously been deferred. In October 2002, as a result of the annual review, the SCPSC reaffirmed SCE&G's billing surcharge of 3.0 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2005, of the balance remaining at December 31, 2002 of $17.9 million.

Transit

On October 15, 2002 SCE&G transferred its transit system to the City of Columbia, South Carolina (City). As part of the transfer agreement, SCE&G will pay the City $32 million over eight years in exchange for a 30-year electric and gas franchise, has conveyed transit-related property and equipment to the City and has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to the City. SCE&G will continue to operate the plant for the City until 2005. SCE&G will also pay the Central Midlands Regional Transit Authority up to $3 million as matching funds for Federal Transit Administration grants for the purchase of new transit coaches and a new transit facility. The cost of the franchise agreement is recorded in other regulatory assets.

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.

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 deferred cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy's gas purchasing practices annually.

PSNC Energy's benchmark cost of gas in effect during the years ended December 2002 and 2001 was as follows:

Rate Per Therm		Effective Date
$.690		January 2001
$.750		February-March 2001
$.650		April-August 2001
$.500		September-October 2001
$.350		November-December 2001
$.300		January 2002
$.215		February-June 2002
$.350		July-October 2002
$.410		November-December 2002

On January 2, 2003 the NCUC approved PSNC Energy's request to increase the benchmark cost of gas from $.410 to $.460 per therm effective for service rendered on and after January 1, 2003. On March 3, 2003 the NCUC approved PSNC Energy's request to increase the benchmark cost of gas from $.460 to $.595 per therm effective March 1, 2003.

In April 2000 the NCUC issued an order permanently approving PSNC Energy's request to establish its commodity cost of gas for large commercial and industrial customers on the basis of market prices for natural gas. This mechanism allows PSNC Energy to collect from its customers amounts approximating the amounts paid for natural gas.

A state expansion fund, established by the North Carolina General Assembly in 1991 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

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June 2000 the NCUC approved PSNC Energy's requests for disbursement of up to $28.4 million from PSNC Energy's expansion fund to extend natural gas service to Madison, Jackson and Swain Counties in western North Carolina. PSNC Energy estimates that the cost of this project will be approximately $31.4 million. The Madison County and Jackson County portions of the project were completed by the end of 2002. At December 31, 2002 approximately $16.9 million had been spent on this project. The unused portion of PSNC Energy's expansion fund is recorded in prepaid assets.

In December 1999 the NCUC issued an order approving SCANA's acquisition of PSNC Energy. As specified in the order, PSNC Energy reduced its rates by approximately $1 million in each of August 2000 and August 2001, and agreed to a moratorium on general rate cases until August 2005. General rate relief can be obtained during this period to recover costs associated with materially adverse governmental actions and force majeure events.

South Carolina Pipeline Corporation

SCPC's purchased gas adjustment for cost recovery and gas purchasing policies are reviewed annually by the SCPSC. In an August 2002 order, the SCPSC found that for the period January 2001 through March 2002 SCPC's gas purchasing policies and practices were prudent and that SCPC properly adhered to the gas cost recovery provisions of its gas tariff.

REGULATORY MATTERS — FEDERAL

SCANA is a registered public utility holding company under PUHCA. SCANA and its subsidiaries are subject to the jurisdiction of the SEC as to financings, acquisitions and diversifications, affiliate transactions and other matters. A customary three-year renewal of the Company's financing and other authorizations under PUHCA was received on February 12, 2003.

The Company's regulated business operations were impacted by FERC Order No. 2000 and other related initiatives of the FERC. Order No. 2000 required each utility under FERC jurisdiction that operates an electric transmission system to submit plans for the possible formation of a regional transmission organization. In March 2001 FERC gave provisional approval to SCE&G and two other southeastern electric utilities to establish GridSouth as an independent regional transmission company, responsible for operating and planning the utilities' combined transmission systems. In June 2002 GridSouth implementation was suspended pending the issuance and evaluation of new FERC directives.

In July 2002 FERC issued a NOPR on Standard Market Design which proposes sweeping changes to the country's existing regulatory framework governing transmission, open access and energy markets and which will attempt, in large measure, to standardize the national energy market. While it is anticipated that significant changes to the NOPR may occur and that implementation, presently scheduled for September 2004, may not occur for some time, any rules standardizing the markets may have significant impact on the Company's access to or cost of power for its native load customers and on the Company's marketing of power outside its service territory. The Company is currently evaluating this NOPR to determine what effect it will have on its operations. Additional directives from FERC are expected later in 2003.

CRITICAL ACCOUNTING POLICIES AND NEW ACCOUNTING STANDARDS

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

SFAS 71 — The Company'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. At December 31, 2002 the Company had recorded approximately $269 million and $114 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities. Management believes the regulatory assets are recoverable through rates. The state commissions which regulate the utilities have reviewed and approved most of the

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items shown as regulatory assets through specific orders. Other items represent costs which were not yet approved for recovery by the state commissions. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in current 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 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.

Certain of the Company's regulatory assets and liabilities arise from its environmental assessment program, which identifies and evaluates 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 expenditures could differ significantly from the original estimates. Regulatory assets and liabilities related to environmental cleanup affect primarily the Gas Distribution segment and are due to the costs associated with current and former MGP sites.

Revenue Recognition / 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 our utilities and retail gas operations are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, we record 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, 2002 and 2001, accounts receivable include unbilled revenues of $107.7 million and $81.1 million, respectively. Total revenues for 2002 and 2001 were $2.95 billion and $3.45 billion, respectively.

Allowance for Funds Used During Construction (AFC) — AFC, a noncash item, 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 is depreciated as a component of plant cost in establishing rates for utility services. The Company's regulated subsidiaries calculated AFC using composite rates of 8.3%, 8.8% and 8.3% for 2002, 2001 and 2000, 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. AFC primarily affects the Electric Operations segment due to its capital-intensive construction program, and to a lesser extent, AFC affects the Gas Distribution and Gas Transmission segments. AFC represented approximately 9.1% of income before income taxes, gains, losses, impairments and the cumulative effect of an accounting change in 2002, 7.2% in 2001 and 2.3% in 2000. Because the equity component of AFC is not taxable, increased AFC reduces the Company's effective tax rate. See Results of Operations for additional discussion.

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 actual write-offs which might be experienced. These estimates are based on, among other things, comparisons of the relative age of accounts and consideration of actual write-off history. The distribution

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segments of the Company's regulated utilities have an established write-off history, and the regulated service areas enable the utilities to reliably estimate their respective provision for bad debts. The Company's Retail Gas Marketing segment operates in Georgia's natural gas market. As such, estimation of the provision for bad debts related to this segment is subject to greater imprecision. In 2002, the Retail Gas Marketing segment expensed approximately $6.2 million related to bad debt, which represents approximately 1.6% of its gross revenue. Had an additional 1% of gross revenues been reserved for bad debts, net income in 2002 would have been reduced by approximately $2.4 million.

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, as well as changes in financial assumptions such as discount rates and timing of cash flows. See also the discussion of the Company's adoption of SFAS 143, "Accounting for Asset Retirement Obligations," below. 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 V.C. Summer Nuclear Station (Summer Station), including the cost of decommissioning plant components not subject to radioactive contamination, totals approximately $357 million, stated in 1999 dollars, based on a decommissioning study completed in 2000. South Carolina Public Service Authority (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 methodology acceptable to the United States 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.

SCE&G's method of funding decommissioning costs is referred to as COMReP (Cost of Money Reduction Plan). Under this plan, funds collected through rates are used to pay premiums on insurance policies on the lives of certain Company personnel. SCE&G is the beneficiary of these policies. Through these insurance contracts, SCE&G is able to take advantage of income tax benefits and accrue earnings on the fund on a tax-deferred basis. 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.

Pension Accounting — SCANA follows SFAS 87, "Employers' Accounting for Pensions," in accounting for its defined benefit pension plan. SCANA'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 returns on assets. Net pension income of $25.8 million recorded in 2002 reflects the use of a 7.5% discount rate and an assumed 9.5% long-term return on plan assets. SCANA believes that these assumptions were, and that the resulting pension income amount was, reasonable.

Due to poor performance in the stock market in recent years, the Company has determined to adjust its assumed long-term return on assets to 9.25% for 2003. Lower interest rates have also led to a reduction in the discount rate as of December 31, 2002 to 6.5%. Had those assumptions been in place in 2002, net pension income would have been reduced by approximately $5.3 million.

In determining the appropriate discount rate, the Company considers the market indices of high-quality long-term fixed income securities.

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As such, the Company selected the above discount rate of 6.5% as being within a reasonable range of Moody's "Aa" interest rate as of December 31, 2002. This same discount rate was also selected for determination of OPEB liabilities discussed below.

The following information with respect to pension assets 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 evaluated input from actuaries and from pension fund investment advisors, including such advisors' review of the plan's historical 10, 16 and 24 year cumulative actual returns of 10.15%, 10.80% and 12.32%, respectively, which have all been in excess of related broad indices. The Company anticipates that investment managers will continue to generate long-term returns of at least 9.25%.

The expected long-term rate of return of 9.25% is based on an asset allocation of 80% with equity managers and 20% with fixed income managers. While management believes that the asset allocation will return to those levels, because of market fluctuations, the actual asset allocation as of December 31, 2002 was 70% with equity managers and 30% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio to the targeted allocation when considered appropriate.

While the recent investment performance and the decline in discount rate have significantly reduced the level of pension income, the pension trust has been and remains adequately funded, and no contributions have been required since 1997. As such, recent declines in pension income have had no impact on the Company's cash flows. Based on stress testing performed by the Company's actuaries, management does not anticipate the need to make pension contributions until at least 2008.

Accounting for Postretirement Benefits other than Pensions — Similar to its pension accounting, SCANA 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 assumptions related to return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. SCANA used a discount rate of 7.5% and recorded a net SFAS 106 cost of $18.3 million for 2002. Had the selected discount rate been 6.5%, the expense for 2002 would have been approximately $1.2 million higher.

SFAS 142 — In connection with the adoption of SFAS 142, "Goodwill and Other Intangible Assets," the Company performed a valuation analysis of its investment in SCPC (Gas Transmission segment) using a discounted cash flow analysis and of PSNC Energy (Gas Distribution segment) using an independent appraisal. The analysis for SCPC indicated that the fair value of related goodwill exceeded its carrying amount. The independent appraisal made various assumptions related to cash flow projections, discount rates, weighted average cost of capital and market multiples for comparable companies. The analysis indicated that the carrying amount of PSNC Energy's acquisition adjustment (goodwill) exceeded its fair value, and as a result, the Company recorded an impairment charge of $230 million as the cumulative effect of an accounting change, effective January 1, 2002. SFAS 142 requires the Company to perform valuation analyses annually. Such analyses will incorporate updated assumptions similar to those used for the initial valuations.

SFAS 143 — SFAS 143 provides guidance for recording and disclosing liabilities related to the future obligations to retire assets (ARO). SFAS 143 applies to the legal obligation associated with the retirement of long-lived tangible assets that result from acquisition, construction, development and normal operations. The Company adopted SFAS 143 effective January 1, 2003. Because such obligation relates solely to the Company's regulated electric utility, adoption of SFAS 143 will have no impact on results of operations; however, the Company will record an ARO of approximately $110 million, which exceeds the

A-19

previously recorded reserve for nuclear plant decommissioning of approximately $87 million.

In addition to the ARO for Summer Station, the Company believes that there is legal uncertainty as to the existence of environmental obligations associated with certain transmission and distribution properties. The Company believes that any ARO related to this type of property would be insignificant and, due to the indeterminate life of the related assets, an ARO could not be reasonably estimated.

The Company's regulated operations record cost of removal as a component of accumulated depreciation for property that does not have an associated legal retirement obligation. As of December 31, 2002, the Company estimates that approximately $325 million of its accumulated depreciation balance is related to this regulatory liability.

OTHER MATTERS

Unconsolidated Special Purpose Entities

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," and it does not engage in off-balance sheet financing or similar transactions other than incidental operating leases in the normal course of business, generally for office space, furniture and equipment.

Synthetic Fuel Investments

SCE&G holds two equity-method investments in partnerships involved in converting coal to alternate fuel, the use of which fuel qualifies for federal income tax credits. The aggregate investment in these partnerships as of December 31, 2002 is approximately $2 million, and through December 31, 2002, they had generated and passed through to SCE&G approximately $58 million in such tax credits. Under a plan approved by the SCPSC, any tax credits generated and ultimately passed through to SCE&G from synfuel produced and consumed by SCE&G have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions. See Note 1B of Notes to Consolidated Financial Statements.

Nuclear License Extension

In August 2002 SCE&G filed an application with the NRC for a 20-year license extension for its Summer Station. If approved, the extension would allow the plant to operate through 2042. SCE&G estimates that it will incur approximately $12 million in costs related to the application process.

Radio Service Network

In April 2002 SCI sold its 800 Mhz radio service network within South Carolina to Motorola, Inc.

Claims and Litigation

In 1999 an unsuccessful bidder for the purchase of propane gas assets of SCANA filed suit against SCANA in South Carolina Circuit Court, seeking unspecified damages. The suit alleges the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. The Company is confident in its position and intends to vigorously defend the lawsuit. The Company does not believe that the resolution of this issue will have a material impact on its results of operations, cash flows or financial position.

In 2001 the Company entered into, in the ordinary course of business, a 15 year take-and-pay contract with an unaffiliated natural gas supplier (Supplier) to purchase 190,000 dekatherms (DT) of natural gas per day beginning in the spring of 2004. In December 2002, as a result of the failure of Supplier and its guarantor to meet contractual obligations related to credit support provisions, the Company terminated the contract. Attempts to negotiate a new contract between the parties were not successful. In February 2003, the Company received notification from Supplier of its request for binding arbitration under the original contract. The Company is confident of the propriety of its actions and will vigorously pursue its position in such arbitration proceedings. 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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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.

Telecommunications Investments

At December 31, 2002 SCH, a wholly owned, indirect subsidiary of SCANA, held investments in the marketable equity and debt securities of the following companies in the amounts noted in the following table.

Investee	Securities	Basis
		(Millions of dollars)
ITC Holding	3.1 million shares common stock	$	5.8
	645,153 shares series A preferred stock, convertible into 2.6 million shares of common stock		7.2
	133,664 shares series B preferred stock, convertible into 534,656 shares of common stock		4.0
ITC^DeltaCom	566,010 shares of common stock		1.1
	149,077 shares series A 8% preferred stock, convertible in 2005 into 2.6 million shares of common stock		12.7
	Warrants to purchase 506,861.8 shares of common stock		1.1
Knology^(a)	7.2 million shares series A preferred stock, convertible into 7.5 million shares of common stock		14.1
	14.8 million shares series C preferred stock, convertible into 14.8 million shares of common stock		35.1
	21.7 million shares series E preferred stock, convertible into 21.7 million shares of common stock		40.6
	$43.6 million face amount, 12% senior unsecured notes due 2009, including accrued interest		43.6

In 2002 SCH sold the 39.3 million shares it held in DTAG through a series of market transactions. See additional information at Results of Operations.

ITC Holding holds ownership interests in several Southeastern communications companies. As these securities are not actively traded, determination of their fair value is not practicable. ITC^DeltaCom is a regional provider of telecommunications services. Knology is a broadband service provider of cable television, telephone and internet services.

In June 2002 ITC^DeltaCom announced plans for a reorganization and entered into Chapter 11 bankruptcy. As a result the Company wrote off its investments in ITC^DeltaCom in the second quarter and recorded an aggregate impairment charge of approximately $7.0 million (after tax). The bankruptcy court accepted the reorganization plan, and ITC^DeltaCom emerged from bankruptcy on October 29, 2002. In connection with ITC^DeltaCom's emergence from bankruptcy, SCH provided $14.9 million in preferred equity financing. The common shares owned by SCH have a market value of $1.3 million, thus an unrealized gain of $0.2 million has been recorded in Other Comprehensive Income. The preferred shares owned by SCH are classified as held to maturity due to their debt features, and the market value is not readily determinable.

In July 2002 Knology negotiated a potential exchange of its Knology Broadband discount notes for a combination of new notes and new preferred stock. In contemplation of the anticipated exchange, the Company recorded an impairment loss of approximately $0.3 million (after-tax) in the second quarter. Because the exchange offer did not result in the requisite minimum tender of notes, in the third quarter Knology filed a prepackaged Chapter 11 bankruptcy plan which reflected the same terms of exchange. The bankruptcy court accepted the reorganization plan, and in connection with Knology's emergence from bankruptcy, SCH purchased an additional 6.5 million shares of series C preferred stock for approximately $19.5 million. The market value of Knology securities as of December 31, 2002 is not readily determinable.

A-21

RESULTS OF OPERATIONS

Earnings (Loss) and Dividends

Earnings (loss) per share of common stock and cash dividends declared for 2002, 2001 and 2000 were as follows:

		2002			2001			2000
Earnings (loss) derived from:
	Continuing operations	$	2.38		$	2.15		$	2.12
	Gains from sales of investments and assets		.24			3.42			—
	Investment impairments		(1.79	)		(.42	)		—
	Cumulative effects of accounting changes, net of taxes		(2.17	)		—			.28

	Earnings (loss) per weighted average share	$	(1.34	)	$	5.15		$	2.40

Cash dividends declared (per share)		$	1.30		$	1.20		$	1.15

•		2002 vs 2001		Earnings derived from continuing operations increased $.23 primarily due to improved margins from sales of electricity of $.36, lower interest expense of $.14, improved results from non-regulated subsidiaries of $.08, increased allowance for funds used during construction of $.06, and lower depreciation and amortization expense of $.02 and other items totaling $.03. These factors were partially offset by higher operations and maintenance expense of $.24, (including $.07 due to lower pension income), lower gas margins of $.15, and higher property taxes of $.07.
•		2001 vs 2000		Earnings derived from continuing operations increased $.03, primarily as a result of improved results from retail gas marketing of $.03, improved results from energy marketing of $.09, completion of repairs at Summer Station in 2000 of $.04, the elimination of the imputed interest expense related to the PSNC Energy acquisition in 2000 of $.05 and other items totaling $.02. These improvements were partially offset by a decrease in electric margin of $.11 and a decrease in regulated gas margin of $.09.

In 2002 the Company recorded an impairment charge of $1.72 per share related to the other than temporary decline in market value of the Company's investment in DTAG. In addition, the Company recorded an impairment charge of $.07 per share related to the other than temporary decline in market value of its investment in ITC^DeltaCom (see Note 11 of Notes to Consolidated Financial Statements). Also, as required by SFAS 142 the Company recorded as the cumulative effect of an accounting change an impairment charge of $2.17 per share related to the acquisition adjustment associated with PSNC Energy (see Note 1G of Notes to Consolidated Financial Statements). In addition, the Company recognized gains of $.09 per share from the sale of the Company's radio service network and $.15 per share in connection with its sale of DTAG shares.

In 2001 the Company recognized a gain of $3.38 per share in connection with the exchange of its investment in Powertel, which was acquired by DTAG in May 2001. The Company also recognized a gain of $.04 per share in connection with the sale of the assets of SCANA Security in March 2001. The Company also recorded impairment charges related to investments in ITC^DeltaCom of $.34 per share, a developer of micro-turbine technology of $.04 per share and a lime production plant of $.04 per share.

In 2000 the cumulative effect of an accounting change resulted from the initial recording of unbilled revenues by SCANA's retail utility subsidiaries (see Note 2 of Notes to Consolidated Financial Statements).

Pension Income

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. However, pension income for 2002 decreased significantly compared to 2001 and 2000, primarily as a result of a less favorable investment market. Pension income during these periods, excluding amounts attributable to Santee Cooper (see

A-22

Note 5), was recorded on the Company's financial statements as follows:

Millions of dollars		2002		2001		2000
Income Statement Impact:
	Reduction in employee benefit costs	$	10.9	$	22.6	$	22.6
	Increase in other income		11.1		12.7		12.8
Balance Sheet Impact:
	Reduction in capital expenditures		3.1		6.2		5.8
	Increase in amount due to Santee Cooper		.7		1.8		2.0

Total Pension Income		$	25.8	$	43.3	$	43.2

See also the discussion of pension accounting in Critical Accounting Policies and New Accounting Standards.

Allowance for Funds Used During Construction (AFC)

The Company's financial statements include the effects of the recording of 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. An equity portion of AFC is included in nonoperating income and a debt portion of AFC is included in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 9.1% of income before income taxes, gains, losses, impairments and the cumulative effect of an accounting change in 2002, 7.2% in 2001 and 2.3% in 2000.

Electric Operations

Electric Operations is comprised of the electric portion of SCE&G, GENCO and Fuel Company. Electric operations sales margins (including transactions with affiliates) for 2002, 2001 and 2000, excluding the cumulative effect of accounting change in 2000, were as follows:

Millions of dollars		2002			2001			2000
Operating revenues		$	1,379.5		$	1,368.7		$	1,343.8
Less:	Fuel used in generation		(329.6	)		(283.3	)		(294.9	)
	Purchased power		(42.1	)		(138.1	)		(82.5	)

Margin		$	1,007.8		$	947.3		$	966.4

•		2002 vs 2001		Margin increased $31.9 million due to more favorable weather and $30.5 million due to customer growth. Fuel used in generation increased and purchased power decreased due to completion of the Urquhart Station repowering project in June 2002 and fewer plant outages during 2002.
•		2001 vs 2000		Sales margin decreased $32.1 million due to milder weather and $12.6 million due to the impact of the slowing economy. These decreases were partially offset by $25.6 million from customer growth.

Increases (decreases) from the prior year in megawatt-hour (MWh) sales volume by classes were as follows:

Classification (in thousands)	2002		% Change
Residential	735.6		11.3	%
Commercial	370.5		5.9	%
Industrial	158.0		2.5	%
Sales for resale (excluding interchange)	333.7		29.9	%
Other	1.1		0.2	%

Total territorial	1,598.9		7.7	%
Negotiated Market Sales Tariff (NMST)	(1,441.7	)	(67.1	)%

Total	157.2		0.7	%

Classification (in thousands)	2001		% Change
Residential	(170.5	)	(2.5	)%
Commercial	(16.8	)	—
Industrial	(317.7	)	(4.8	)%
Sales for resale (excluding interchange)	(108.3	)	(8.8	)%
Other	(18.9	)	(3.4	)%

Total territorial	(632.2	)	(3.0	)%
NMST	208.0		10.0	%

Total	(424.2	)	(2.0	)%

•		2002 vs 2001		Territorial sales volume increased primarily due to more favorable weather. The decrease in NMST volumes reflects the Company's recording of buy-resale transactions in Other Income in 2002.
•		2001 vs 2000		Territorial sales volume decreased primarily due to milder weather.

Gas Distribution

Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC

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Energy. Gas distribution sales margins (including transactions with affiliates) for 2002, 2001 and 2000, excluding the cumulative effect of accounting change in 2000, were as follows:

Millions of dollars		2002			2001			2000
Operating revenues		$	653.9		$	793.6		$	745.9
Less: Gas purchased for resale			(401.0	)		(537.8	)		(486.3	)

	Margin	$	252.9		$	255.8		$	259.6

Sales margin decreased slightly over the three year period primarily as a result of the slowing economy and increased competition with alternate fuels.

Increases (decreases) from the prior year in DT sales volume by classes, including transportation gas, were as follows:

Classification (in thousands)	2002	% Change
Residential	3,707.2	11.6%
Commercial	1,344.2	5.7%
Industrial	1,668.4	8.5%
Transportation gas	1,986.2	7.0%
Sales for resale	0.1	6.1%

Total	8,706.1	8.4%

Classification (in thousands)	2001		% Change
Residential	(7,068.1	)	(18.1	)%
Commercial	(2,613.2	)	(10.0	)%
Industrial	(2,860.0	)	(12.7	)%
Transportation gas	(3,318.6	)	(10.5	)%
Sales for resale	1.0		*

Total	(15,858.9	)	(13.3	)%

*: Not meaningful

•		2002 vs 2001		Residential and commercial sales volume increased primarily due to more favorable weather. Industrial and transportation gas volumes increased in 2002 after the volatility of the natural gas market in 2001 had resulted in interruptible customers using their alternate fuel sources during that year.
•		2001 vs 2000		Residential sales volume decreased due to higher gas prices. Industrial and transportation gas decreased due to the volatility of the natural gas market resulting in interruptible customers using alternate fuel sources.

Gas Transmission

Gas Transmission is comprised of the operations of SCPC. Gas transmission sales margins (including transactions with affiliates) for 2002, 2001 and 2000 were as follows:

Millions of dollars		2002			2001			2000
Operating revenues		$	479.1		$	478.0		$	489.0
Less: Gas purchased for resale			(442.4	)		(434.1	)		(434.7	)

	Margin	$	36.7		$	43.9		$	54.3

•		2002 vs 2001		Sales margin decreased $9.6 million due to the unfavorable competitive position of natural gas relative to alternate fuels in the first quarter, which was partially offset by a favorable competitive position in the remaining quarters of $1.4 million and increased sales for electric generation of $1.0 million.
•		2001 vs 2000		Sales margin decreased primarily as a result of decreased volume of sales to industrial customers due to competitive pricing of alternate fuels and a slowing economy of $8.5 million, decreased volume of sales to electric generation due to milder weather of $1.4 million and reduced margins in sales for resale as a result of milder weather of $0.5 million.

Increases (decreases) from the prior year in DT sales volume by classes including transportation were as follows:

Classification (in thousands)	2002	% Change
Commercial	46.1	64.5	%
Industrial	17,402.5	59.6	%
Transportation	770.2	25.8	%
Sales for resale	4,299.7	8.2	%

Total	22,518.5	26.5	%

Classification (in thousands)	2001		% Change
Commercial	(42.2	)	(37.2	)%
Industrial	(10,127.6	)	(25.8	)%
Transportation	725.1		32.1	%
Sales for resale	(9,529.6	)	(15.3	)%

Total	(18,974.3	)	(18.3	)%

•

2002 vs 2001

Industrial volumes increased 3,732.2 thousand DTs due to increased electric generation and 4,395.8 thousand DTs due to the emergence from bankruptcy of a large industrial customer. The remaining increase is primarily due to improved competition with alternate fuels. Sales for resale volumes increased due to more favorable weather.

A-24

•

2001 vs 2000

Commercial and industrial volumes decreased primarily due to increased gas to gas competition. Transportation volumes increased due to increased gas to gas competition. Sales for resale volumes decreased due to milder weather.

Retail Gas Marketing

Retail Gas Marketing is comprised of SCANA Energy, a division of SCANA Energy Marketing, Inc., which operates in Georgia's natural gas market. Retail Gas Marketing revenues and net income for 2002, 2001 and 2000 were as follows:

Millions of dollars		2002			2001			2000
Operating revenues		$	379.5		$	453.8		$	412.8
Net income			14.3			6.8			3.2

•		2002 vs 2001		Operating revenues decreased primarily as a result of lower average retail prices and lower volumes. Net income increased primarily due to lower bad debt expense of $8.1 million, lower interest and depreciation expense of $1.6 million and lower effective tax rate of $0.8 million, which were partially offset by a decrease in gas margin of $2.1 million and higher operating expenses of $0.9 million.
•		2001 vs 2000		Operating revenues increased due to higher average retail prices. Net income increased primarily as a result of increases in gross margins on gas sales.

Delivered volumes for 2002, 2001 and 2000 totaled approximately 33.8 million, 36.0 million and 43.1 million DT, respectively.

Energy Marketing

Energy Marketing is comprised of the Company's non-regulated marketing operations, excluding SCANA Energy. Energy Marketing operating revenues and net income (loss) for 2002, 2001 and 2000 were as follows:

Millions of dollars		2002			2001			2000
Operating revenues		$	316.8		$	613.4		$	677.9
Net income (loss)			(.8	)		3.4			(3.1	)

•		2002 vs 2001		Operating revenues decreased primarily due to lower natural gas prices and lower volumes. Net income decreased $5.3 million primarily from the decreased activity and subsequent closing of SCANA Energy Trading, LLC and $1.7 million due to lower margins related to decreased gas prices and decreased volumes. These decreases were partially offset by increases of $1.3 million due to the closing of the unprofitable Midwest office in 2001 and $1.5 million lower bad debt expense.
•		2001 vs 2000		Operating revenues decreased $104.8 million primarily due to the closing of the Midwest and California offices in 2001, which was partially offset $40.3 million by higher average retail prices. Net income improved primarily due to improved margins.

Delivered volumes for 2002, 2001 and 2000 totaled approximately 86.2 million, 114.6 million and 149.6 million DT, respectively, which include interruptible volumes of approximately 33.8 million, 36.0 million and 28.1 million DT for the same periods, respectively. The decrease in volumes for 2001 resulted from the closing of the Midwest and California offices.

Other Operating Expenses

Increases (decreases) in other operating expenses were as follows:

Millions of dollars	2002			% Change
Other operation and maintenance	$	41.4		8.6	%
Depreciation and amortization		(3.8	)	(1.7	)%
Other taxes		11.6		10.1	%

Total	$	49.2		6.0	%

Millions of dollars	2001		% Change
Other operation and maintenance	$	3.5	0.7	%
Depreciation and amortization		7.2	3.3	%
Other taxes		1.5	21.3	%

Total	$	12.2	1.5	%

•

2002 vs 2001

Other operation and maintenance expenses increased primarily due to lower pension income of $11.6 million, increased labor and benefits of $19.2 million, increased nuclear refueling maintenance of $4.0 million, increased cost at Cogen South of $3.1 million, higher property insurance of $2.6 million, increased amortization of environmental costs of $3.0 million and increased storm damage expenses of $1.8 million. These increases were partially offset by lower bad debt expense of $7.0 million. Depreciation and amortization decreased primarily due to implementation of SFAS 142 and the resulting elimination of amortization expense related to goodwill of $14.0 million — see Note 1G of Notes to Consolidated Financial Statements, which was partially offset by increases for the completion of the Urquhart Station repowering project in June 2002 of $4.8 million and normal net property additions of $5.4 million. Other taxes increased primarily due to increased property taxes.

A-25

•

2001 vs 2000

Other operation and maintenance expenses increased primarily as a result of increases in employee benefits. Depreciation and amortization increased primarily as a result of normal increases in utility plant. Other taxes increased primarily due to increased property taxes.

Other Income

Increases (decreases) in other income, excluding the equity component of AFC, were as follows:

Millions of dollars	2002			% Change
Gain on sale of investments	$	(521.7	)	*
Gain on sale of assets		4.1		33.3%
Impairment of investments		(228.8	)	*
Other income		8.6		21.7%

Total	$	(737.8	)	*

Millions of dollars	2001			% Change
Gain on sale of investments	$	545.3		*
Gain on sale of assets		10.5		*
Impairment of investments		(61.9	)	*
Other income		0.4		1.0%

Total	$	494.3		*

*: Not meaningful

•		2002 vs 2001		Gain on sale of investments was higher in 2001 than in 2002 primarily as a result of the gain of $545.3 million recognized in May 2001 in connection with the exchange of the Company's investment in Powertel for shares of DTAG, and the March 2001 gain of $7.8 million on the sale of the assets of SCANA Security. In 2002, the Company recognized gains of $15.6 million and $23.6 million in connection with the sale of the Company's radio service network and the sale of all DTAG stock. Impairment of investments increased due to the impairment writedowns of the Company's investments in DTAG and ITC^DeltaCom.
•		2001 vs 2000		Other income increased primarily as a result of the gain recognized in May 2001 in connection with the exchange of the Company's investment in Powertel for shares of DTAG, and the March 2001 gain on the sale of the assets of SCANA Security. These gains were partially offset by impairments related to investments in ITC^DeltaCom, a developer of micro-turbine technology and a lime production plant.

Interest Expense

Increases (decreases) in interest expense, excluding the debt component of AFC, were as follows:

Millions of dollars		2002		% Change
Interest on long-term debt, net		$(18.8	)	(8.4	)%
Other interest expense		(4.0	)	(39.6	)%

	Total	$(22.8	)	(9.8	)%

Millions of dollars		2001		% Change
Interest on long-term debt, net		$17.8		8.6	%
Other interest expense		(14.4	)	(58.8	)%

	Total	$ 3.4		1.5	%

•

2002 vs 2001

Interest expense decreased by $18.8 million as a result of lower interest rates, by $2.0 million due to decreased borrowings and by $1.4 million due to lower amortization of debt expense which occurred as a result of debt payoffs.

A-26

•

2001 vs 2000

Interest expense increased by $20.0 million due to increased borrowings. Such increase was partially offset by decreases of $6.0 million due to declining variable interest rates, $5.2 million due to the Company's use of interest rate swap contracts to convert higher fixed rate debt to lower variable rate debt and $5.4 million due to a decrease in principal and the weighted average interest rate on short-term debt.

Income Taxes

Income taxes decreased approximately $268.9 million in 2002 compared to 2001 and increased approximately $163.8 million in 2001 compared to 2000. Changes in income taxes are primarily due to changes in Other Income described above. The Company's effective tax rate for 2002, excluding the cumulative effect of accounting change, was approximately 26.7%, which reflects the impact of higher equity AFC and the change in tax regulations effective in 2002 allowing for the tax deductibility of certain dividends paid on SCANA stock held in the Company's Stock Purchase Savings Plan.

A-27

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 table presents 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, 2002 (Millions of dollars) Liabilities		2003	2004	2005	2006	2007	Thereafter	Total	Fair Value
Long-Term Debt:
Fixed Rate ($)		313.3	201.9	196.8	177.3	71.3	2,174.2	3,134.8	3,267.2
Average Fixed Interest Rate (%)		7.26	7.51	7.37	8.47	6.94	6.73	6.97
Variable Rate ($)		100.0	150.0	—	—	—	—	250.0	249.3
Average Variable Interest Rate (%)		3.11	2.71	—	—	—	—	2.87
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)		7.5	57.5	3.2	3.2	28.2	241.0	340.6	9.0
	Average Pay Interest Rate (%)	6.17	6.13	4.59	4.59	4.60	3.05	3.79
	Average Receive Interest Rate (%)	9.47	7.70	8.75	8.75	7.11	6.21	6.65

		Expected Maturity Date
December 31, 2001 (Millions of dollars) Liabilities		2002	2003	2004	2005	2006	Thereafter	Total	Fair Value
Long-Term Debt:
Fixed Rate ($)		38.3	298.5	187.0	182.0	162.8	1,728.0	2,596.6	2,602.8
Average Fixed Interest Rate (%)		7.21	6.38	7.58	7.43	8.63	7.02	6.64
Variable Rate ($)		700.0	202.0	—	—	—	—	902.0	898.2
Average Variable Interest Rate (%)		2.82	3.45	—	—	—	—	2.96
Interest Rate Swaps:
Pay Variable/Receive Fixed ($)		4.3	7.5	7.5	3.2	3.2	319.2	344.9	1.2
	Average Pay Interest Rate (%)	7.82	6.73	6.73	5.26	5.26	3.08	3.34
	Average Receive Interest Rate (%)	10.0	9.47	9.47	8.75	8.75	6.46	6.68

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.

In addition, at December 31, 2002 the Company held investments in the 12% senior unsecured notes (due 2009) of a telecommunications company, the cost basis of which, including accrued interest, is approximately $43.6 million. As these notes are not actively traded, determination of their fair value is not practicable.

Commodity price risk — The tables below provide information about the Company's financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 mmbtu. Fair values represent quoted market prices.

A-28

		Expected Maturity in 2003
As of December 31, 2002 (Millions of dollars, except weighted average settlement price and strike price) Natural Gas Derivatives:		Expected Maturity in 2003
		Settlement Price^(a)	Contract Amount	Fair Value
Futures Contracts:
	Long($)	4.65	15.6	18.7
	Short($)	4.62	3.6	4.5

		Strike Price^(a)	Contract Amount
Options:
	Purchased put (short)($)	4.25	8.8
	Purchased call (long)($)	4.11	16.5
	Sold put (long) ($)	2.30	2.7

		Expected Maturity in 2002			Expected Maturity in 2003
As of December 31, 2001 (Millions of dollars, except weighted average settlement price) Natural Gas Derivatives:		Expected Maturity in 2002			Expected Maturity in 2003
		Settlement Price^(a)	Contract Amount	Fair Value	Settlement Price^(a)	Contract Amount	Fair Value
Futures Contracts:
	Long($)	2.63	119.3	76.0	3.26	3.0	2.6
	Short($)	2.64	1.6	1.1	—	—	—

(a): weighted average

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

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. The Company'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 of the Company, provides assurance to 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 that are allowed.

The NYMEX futures information above includes those financial positions of both Energy Marketing and SCPC. 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 SCPSC has ruled that the results of SCPC's hedging activities are to be included in the PGA. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability.

Beginning in January 2003, PSNC Energy initiated a hedging program for gas purchasing activities using NYMEX futures and options. PSNC Energy's tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. PSNC Energy will include in its PGA the results of its hedging program, and will seek approval of this accounting treatment from the

A-29

NCUC during the annual prudence review in 2003. The offset to the change in fair value of these derivatives will be recorded as a regulatory asset or liability.

Equity price risk — Investments in telecommunications companies' equity securities (excluding preferred stock with significant debt characteristics) are carried at market value or, if market value is not readily determinable, at cost. The carrying value of the Company's investments in such securities totaled $109.1 million at December 31, 2002. A temporary decline in value of ten percent would result in a $10.9 million reduction in fair value and a corresponding adjustment, net of tax effect, to the related equity account for unrealized gains/losses, a component of Other Comprehensive Income (Loss). An other than temporary decline in value of ten percent would result in a $10.9 million reduction in fair value and a corresponding adjustment to net income, net of tax effect.

A-30

INDEPENDENT AUDITORS' REPORT

SCANA Corporation:

We have audited the accompanying Consolidated Balance Sheets and Statements of Capitalization of SCANA Corporation (Company) as of December 31, 2002 and 2001 and the related Consolidated Statements of Operations, Comprehensive Income (Loss) and Changes in Common Equity and of Cash Flows for each of the three years in the period ended December 31, 2002. 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 auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2002 and 2001 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 1 and 2 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets," effective January 1, 2002 and changed its method of accounting for operating revenues associated with its regulated utility operations effective January 1, 2000.

Columbia, South Carolina
February 7, 2003

A-31

SCANA Corporation
CONSOLIDATED BALANCE SHEETS

				December 31,
				2002			2001
				(Millions of dollars)
Assets
Utility Plant (Note 6):
	Electric			$	5,228		$	4,855
	Gas				1,593			1,536
	Other				184			187

	Total				7,005			6,578
	Accumulated depreciation and amortization				(2,476	)		(2,364	)

	Total				4,529			4,214
	Construction work in progress				677			544
	Nuclear fuel, net of accumulated amortization				38			45
	Acquisition adjustments, net of accumulated amortization (Notes 2 & 3)				230			460

	Utility Plant, Net				5,474			5,263

Nonutility Property, Net of Accumulated Depreciation					95			93
Investments (Note 11)					231			194

	Nonutility Property and Investments, Net				326			287

Current Assets:
	Cash and temporary investments (Note 11)				397			212
	Receivables, net of allowance for uncollectible accounts of $17 and $37				486			424
	Inventories (at average cost):
		Fuel			166			164
		Materials and supplies			61			59
		Emission allowances			10			13
	Prepayments				40			21
	Investments (Note 11)				—			664

	Total Current Assets				1,160			1,557

Deferred Debits:
	Environmental				27			34
	Nuclear plant decommissioning fund				87			79
	Pension asset, net (Note 5)				265			239
	Other regulatory assets				269			210
	Other				146			153

	Total Deferred Debits				794			715

			Total	$	7,754		$	7,822

A-32

SCANA Corporation
CONSOLIDATED BALANCE SHEETS (Continued)

			December 31,
			2002	2001
			(Millions of dollars)
Capitalization and Liabilities
Shareholders' Investment:
	Common equity (Note 8)		$2,177	$2,194
	Preferred stock (Not subject to purchase or sinking funds) (Note 9)		106	106

		Total Shareholders' Investment	2,283	2,300
Preferred Stock, net (Subject to purchase or sinking funds) (Note 9)			9	10
SCE&G — Obligated Mandatorily Redeemable Preferred Securities of SCE&G's Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount of 7.55% Junior Subordinated Debentures of SCE&G, due 2027 (Note 9)			50	50
Long-Term Debt, net (Notes 6 & 11)			2,834	2,646

	Total Capitalization		5,176	5,006

Current Liabilities:
	Short-term borrowings (Notes 7 & 11)		209	165
	Current portion of long-term debt (Notes 6 & 11)		413	739
	Accounts payable		363	275
	Customer deposits		39	41
	Taxes accrued		78	82
	Interest accrued		52	45
	Dividends declared		39	34
	Deferred income taxes, net (Note 10)		4	154
	Other		42	26

	Total Current Liabilities		1,239	1,561

Deferred Credits:
	Deferred income taxes, net (Note 10)		747	720
	Deferred investment tax credits (Note 10)		118	118
	Reserve for nuclear plant decommissioning		87	79
	Postretirement benefits (Note 5)		131	122
	Other regulatory liabilities		114	100
	Other		142	116

	Total Deferred Credits		1,339	1,255

Commitments and Contingencies (Note 12)			—	—

		Total	$7,754	$7,822

See Notes to Consolidated Financial Statements.

A-33

SCANA Corporation
CONSOLIDATED STATEMENTS OF OPERATIONS

			For the Years Ended December 31,
			2002			2001			2000
			(Millions of Dollars, except per share amounts)
Operating Revenues (Notes 2 & 4):
	Electric		$	1,380		$	1,369		$	1,344
	Gas — regulated			878			1,015			998
	Gas — nonregulated			696			1,067			1,091

		Total Operating Revenues		2,954			3,451			3,433

Operating Expenses:
	Fuel used in electric generation			330			283			295
	Purchased power			42			138			82
	Gas purchased for resale			1,199			1,681			1,694
	Other operation and maintenance			522			482			477
	Depreciation and amortization			220			224			217
	Other taxes			127			115			114

		Total Operating Expenses		2,440			2,923			2,879

Operating Income				514			528			554

Other Income (Expense):
	Other income, including allowance for equity funds used during construction of $23, $15 and $3			71			55			41
	Gain on sale of investments and assets (Note 11)			40			557			3
	Impairment of investments (Note 11)			(291	)		(62	)		—

		Total Other Income (Expense)		(180	)		550			44

Income Before Interest Charges, Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change				334			1,078			598
Interest Charges, Net of Allowance for Borrowed Funds Used During Construction of $12, $11 and $6				199			223			225

Income Before Income Taxes, Preferred Stock Dividends and Cumulative Effect of Accounting Change				135			855			373
Income Taxes (Note 10)				36			305			141

Income Before Preferred Stock Dividends and Cumulative Effect of Accounting Change				99			550			232
Dividend Requirement of SCE&G — Obligated Mandatorily Redeemable Preferred Securities				4			4			4

Income Before Cash Dividends on Preferred Stock of Subsidiary and Cumulative Effect of Accounting Change				95			546			228
Cash Dividends on Preferred Stock of Subsidiary (At stated rates)				7			7			7

Income Before Cumulative Effect of Accounting Change				88			539			221
Cumulative Effect of Accounting Change, net of taxes (Note 2)				(230	)		—			29

Net Income (Loss)			$	(142	)	$	539		$	250

Basic and Diluted Earnings (Loss) Per Share of Common Stock:
	Before Cumulative Effect of Accounting Change		$	0.83		$	5.15		$	2.12
	Cumulative Effect of Accounting Change, net of taxes (Note 2)			(2.17	)		—			.28

	Basic and Diluted Earnings (Loss) Per Share		$	(1.34	)	$	5.15		$	2.40

Weighted Average Common Shares Outstanding (millions)				106.0			104.7			104.5

See Notes to Consolidated Financial Statements.

A-34

SCANA Corporation
CONSOLIDATED STATEMENTS OF CASH FLOWS

				For the Years Ended December 31,
				2002			2001			2000
				(Millions of dollars)
Cash Flows From Operating Activities:
Net income (loss)				$	(142	)	$	539		$	250
Adjustments to reconcile net income (loss) to net cash provided from operating activities:
	Cumulative effect of accounting change, net of taxes				230			—			(29	)
	Depreciation and amortization				233			236			227
	Amortization of nuclear fuel				20			16			16
	Gain on sale of assets and investments				(40	)		(558	)		(3	)
	Impairment of investments				291			62			—
	Hedging activities				42			(65	)		—
	Allowance for funds used during construction				(35	)		(26	)		(9	)
	Over (under) collection, fuel adjustment clauses				(15	)		20			(25	)
	Changes in certain assets and liabilities:
		(Increase) decrease in receivables			(64	)		262			(258	)
		(Increase) decrease in inventories			(1	)		(53	)		3
		(Increase) decrease in prepayments			(19	)		(18	)		3
		(Increase) decrease in pension asset			(26	)		(43	)		(43	)
		(Increase) decrease in other regulatory assets			6			(3	)		4
		Increase (decrease) in deferred income taxes, net			(185	)		189			61
		Increase (decrease) in other regulatory liabilities			39			22			6
		Increase (decrease) in postretirement benefits			9			9			15
		Increase (decrease) in accounts payable			88			(119	)		155
		Increase (decrease) in taxes accrued			(4	)		28			(55	)
		Increase (decrease) in interest accrued			7			3			9
	Changes in other assets				8			8			9
	Changes in other liabilities				52			(13	)		55

Net Cash Provided From Operating Activities					494			496			391

Cash Flows From Investing Activities:
	Utility property additions and construction expenditures, net of AFC				(675	)		(523	)		(334	)
	Purchase of subsidiary, net of cash acquired				—			—			(212	)
	Proceeds on sale of investments and assets				568			28			8
	Increase in nonutility property				(19	)		(25	)		(27	)
	Investments in affiliates				(62	)		(46	)		(20	)

Net Cash Used For Investing Activities					(188	)		(566	)		(585	)

Cash Flows From Financing Activities:
	Proceeds:
		Issuance of common stock			149			—			—
		Issuance of First Mortgage Bonds			295			149			148
		Issuance of Industrial Revenue Bonds			87			—			—
		Issuance of notes and loans			497			648			998
		Swap settlement			29			6			—
	Repayments:
		Mortgage bonds			(104	)		—			(100	)
		Notes and loans			(915	)		(317	)		(183	)
		Pollution Control Facilities Revenue Bonds			(62	)		—			—
		Retirement of preferred stock			(1	)		—			(1	)
		Retirement of common stock			—			—			(488	)
	Dividends and distributions:
		Common stock			(133	)		(123	)		(124	)
		Preferred stock			(7	)		(7	)		(7	)
Short-term borrowings, net					44			(233	)		(6	)

Net Cash Provided From (Used For) Financing Activities					(121	)		123			237

Net Increase in Cash and Temporary Investments					185			53			43
Cash and Temporary Investments, January 1					212			159			116

Cash and Temporary Investments, December 31				$	397		$	212		$	159

Supplemental Cash Flow Information:
Cash paid for — Interest (net of capitalized interest of $12, $6 and $4)				$	192		$	219		$	207
			— Income taxes		190			71			120
Noncash Investing and Financing Activities:
	Unrealized gain (loss) on securities available for sale, net of tax				87			(226	)		(197	)
	Columbia Franchise Agreement				30			—			—

In connection with the purchase of Public Service Company of North Carolina, Incorporated in 2000, assets with a fair value of $1,177 million were acquired, cash of $212 million was paid, SCANA stock valued at $488 million was issued, and liabilities of $477 million were assumed.

See Notes to Consolidated Financial Statements.

A-35

SCANA Corporation
CONSOLIDATED STATEMENTS OF CAPITALIZATION

								December 31,
								2002				2001
								(Millions of dollars)
Common Equity (Note 8):
	Common stock, without par value, authorized 150,000,000 shares; issued and outstanding, 110,831,307 shares in 2002 and 104,728,208 in 2001							$1,192				$1,043
	Accumulated other comprehensive income (loss)							1				(113	)
	Retained earnings							984				1,264

Total Common Equity								2,177		42	%	2,194		44	%

South Carolina Electric & Gas Company:
Cumulative Preferred Stock (Not subject to purchase or sinking funds)
		$100 Par Value — Authorized 1,200,000 shares
		$50 Par Value — Authorized 125,209 shares
					Shares Outstanding
					Shares Outstanding		Redemption Price
			Series		2002	2001	Redemption Price
		$100 Par	6.52	%	1,000,000	1,000,000	$100.00	100				100
		$50 Par	5.00	%	125,209	125,209	52.50	6				6

Total Preferred Stock (Not subject to purchase or sinking funds) (Note 9)								106		2	%	106		2	%

South Carolina Electric & Gas Company:
		Cumulative Preferred Stock (Subject to purchase and sinking funds)
		$100 Par Value — Authorized 1,550,000 shares; None outstanding in 2002 and 2001
		$50 Par Value — Authorized 1,539,973 shares
					Shares Outstanding
					Shares Outstanding		Redemption Price
			Series		2002	2001	Redemption Price
			4.50% & 4.60%^(A)		18,849	22,449	$51.00	1				2
			4.60	%^(B)	51,000	54,400	50.50	3				3
			5.125	%	65,000	66,000	51.00	3				3
			6.00	%	65,124	66,635	50.50	3				3

			Total		199,973	209,484

		$25 Par Value — Authorized 2,000,000 shares; None outstanding in 2002 and 2001

Total Preferred Stock (Subject to purchase or sinking funds)								10				11
Less: Current portion, including sinking fund requirements								(1	)			(1	)

Total Preferred Stock, Net (Subject to purchase or sinking funds) (Notes 9 & 11)								9		—	%	10		—	%

SCE&G — Obligated Mandatorily Redeemable Preferred Securities of SCE&G's Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount of 7.55% Junior Subordinated Debentures of SCE&G, due 2027 (Note 9)								50		1	%	50		1	%

A-36

SCANA Corporation
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Continued)

						December 31,
						2002					2001
						(Millions of dollars)
Long-Term Debt (Notes 6 & 11)
SCANA Corporation:
			Series		Year of Maturity
	Medium-Term Notes:		3.08	%⁽¹⁾	2002		—				$	300
			2.63	%⁽¹⁾	2002		—					400
			6.51	%	2003	$	20					20
			6.05	%	2003		60					60
			6.25	%	2003		75					75
			3.45	%⁽¹⁾	2003		—					202
			2.275	%⁽²⁾	2003		100					—
			7.44	%⁽³⁾	2004		50					50
			2.315	%⁽⁴⁾	2004		150					—
			6.90	%⁽³⁾	2007		25					25
			5.81	%⁽³⁾	2008		115					115
			6.875	%	2011		300					300
			6.25	%⁽³⁾	2012		250					—
	Fair value of interest rate swaps						40					7
South Carolina Electric & Gas Company:
			Series		Year of Maturity
	First Mortgage Bonds:		6¹/4	%	2003		100					100
			7.70	%	2004		100					100
			7¹/2	%	2005		150					150
			6¹/8	%	2009		100					100
			6.70	%	2011		150					150
			7¹/8	%	2013		150					150
			7¹/2	%	2023		150					150
			7⁵/8	%	2023		100					100
			7⁵/8	%	2025		100					100
			6.63	%	2032		300					—
	First and Refunding Mortgage Bonds:		9	%	2006		131					131
			8⁷/8	%	2021		—					103
Pollution Control Facilities Revenue Bonds:
		Fairfield County Series 1984 (6.50%)					—					57
		Orangeburg County Series 1994, due 2024 (5.70%)					30					30
		Other					11					16
	Industrial Revenue Bonds (4.2%-5.5%)						90					—
	Franchise Agreements						17					4
South Carolina Generating Company, Inc.:
	Berkeley County Pollution Control Facilities Revenue Bonds, Series 1984, due 2014 (6.50%)						36					36
	Note, 7.78%, due 2011						38					41
Public Service Company of North Carolina, Incorporated:
			Series		Year of Maturity
	Senior Debentures:		10	%⁽³⁾	2004		9					13
			8.75	%⁽³⁾	2012		32					32
			6.99	%	2026		50					50
			7.45	%	2026		50					50
	Medium-Term Notes		6.625	%	2011		150					150
	Fair value of interest rate swaps						3					—
South Carolina Pipeline Corporation Notes, 6.72%, due 2013							14					15
Other							5					6

Total Long-Term Debt							3,251					3,388
Less — Current maturities, including sinking fund requirements							(413	)				(738	)
— Unamortized discount							(4	)				(4	)

Total Long-Term Debt, Net							2,834		55	%		2,646		53	%

Total Capitalization						$	5,176		100	%	$	5,006		100	%

(1) Rate at repayment
(2) Current rate, based on three-month LIBOR + 87.5 basis points reset quarterly
(3) Fixed rate debt hedged by variable interest rate swap
(4) Current rate, based on three-month LIBOR + 62.5 basis points reset quarterly

See Notes to Consolidated Financial Statements.

A-37

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

			For the years Ended December 31,
			2002						2001						2000
			Common Equity			Comprehensive Income (Loss)			Common Equity			Comprehensive Income			Common Equity			Comprehensive Income
			(Millions of Dollars)
Retained Earnings:

	Balance at January 1		$	1,264					$	850					$	720
		Net Income (loss)		(142	)	$	(142	)		539		$	539			250		$	250
		Dividends declared on common stock		(138	)					(125	)					(120	)

	Balance at December 31			984						1,264						850


Accumulated other comprehensive income (loss):
	Balance at January 1			(113	)					139						336
		Unrealized gains (losses) on securities, net of taxes ($47, $(121) and $(106) in 2002, 2001, and 2000, respectively)		87			87			(226	)		(226	)		(197	)		(197	)
		Cumulative effect of change in accounting for hedging activities, net of taxes ($12 in 2001)		—			—			23			23			—			—
		Unrealized gains (loss) on hedging activities, net of taxes ($15 and $(26) in 2002 and 2001, respectively)		27			27			(49	)		(49	)		—			—

	Comprehensive income (loss)					$	(28	)				$	287					$	53

	Balance at December 31			1						(113	)					139


Common Stock:
	Balance at January 1			1,043						1,043						1,043
		Shares issued		149						—						488
		Shares repurchased		—						—						(488	)

	Balance at December 31			1,192						1,043						1,043

Total Common Equity			$	2,177					$	2,194					$	2,032

See Notes to Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A. Organization and Principles of Consolidation

SCANA Corporation (the Company), a South Carolina corporation, is a registered public utility holding company within the meaning of the Public Utility Holding Company Act of 1935, as amended (PUHCA). The Company, through wholly owned subsidiaries, is engaged predominately 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, holds investments in telecommunications companies and provides fiber optic communications in South Carolina.

The accompanying Consolidated Financial Statements reflect the accounts of the Company, the following wholly owned subsidiaries, and three other wholly owned subsidiaries in liquidation.

Regulated businesses

South Carolina Electric & Gas Company (SCE&G)

South Carolina Fuel Company, Inc. (Fuel Company)

South Carolina Generating Company, Inc. (GENCO)

South Carolina Pipeline Corporation (SCPC)

Public Service Company of North Carolina, Incorporated (PSNC Energy)

SCG Pipeline, Inc.

Nonregulated businesses

SCANA Energy Marketing, Inc.

SCANA Communications, Inc. (SCI)

ServiceCare, Inc.

Primesouth, Inc.

SCANA Resources, Inc.

SCANA 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, "Accounting for the Effects of Certain Types of Regulation." SFAS 71 requires cost-based rate-regulated utilities to recognize in their financial statements 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, 2002, approximately $296 million and $114 million of regulatory assets and liabilities, respectively, as shown below.

	December 31,
Millions of dollars	2002			2001
Accumulated deferred income taxes, net	$	95		$	98
Under-(over-)collections — Electric Fuel and Gas Cost Adjustment Clauses		61			46
Deferred environmental remediation costs		27			35
Deferred non-conventional fuel tax benefits, net		(40	)		(17	)
Storm damage reserve		(32	)		(26	)
Franchise agreements		65			—
Other		6			8

Total	$	182		$	144

Accumulated deferred income taxes represent deferred income tax liabilities applicable to utility operations that have not been reflected in customer rates for which future recovery is probable, offset by deferred income tax assets, which will be reflected in customer rates as a result of reduced revenue requirements due to the amortization of deferred investment tax credits.

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Under-(over-)collections — fuel adjustment clauses represent amounts over- or 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 environmental remediation costs represent costs associated with the assessment and clean up of environmental sites at 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, and such costs, totaling approximately $18 million, are expected to be fully recovered by the end of 2005. A portion of the costs incurred at sites owned by PSNC Energy are also being recovered through rates, and management believes the remaining costs of approximately $7.8 million will be recoverable in the future. Amounts incurred to date that have not been recovered through gas rates are approximately $1.2 million.

Deferred non-conventional fuel tax benefits represent the deferral of partnership losses and other expenses, offset by the accumulated deferred income tax credits associated with two SCE&G partnerships involved in converting coal to alternate fuel. Under a plan approved by the SCPSC, any net tax credits generated from non-conventional fuel produced and consumed by SCE&G and ultimately passed through to SCE&G have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions.

The storm damage reserve represents an SCPSC approved reserve account capped at $50 million to be collected through rates over a ten-year period. The accumulated storm damage reserve can be applied to offset actual storm damage costs in excess of $2.5 million in a calendar year.

Franchise agreements represent costs associated with the 30-year electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina.

The SCPSC and the NCUC 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 the SCPSC or the NCUC. 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 SCPSC or NCUC 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 in the period the write-off would be recorded, but it is not expected that cash flows or financial position would be materially affected.

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 the Federal Energy Regulatory Commission (FERC).

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, along with the cost of removal, less salvage, to accumulated depreciation. The costs of repairs, replacements and renewals of items

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of property determined to be less than a unit of property are charged to maintenance expense.

SCE&G, operator of the V.C. Summer Nuclear Station (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 approximately $962.4 million and $963.0 million as of December 31, 2002 and 2001, respectively. Accumulated depreciation associated with SCE&G's share of Summer Station was approximately $417.9 million and $407.4 million as of December 31, 2002 and 2001, respectively. SCE&G's share of the direct expenses associated with operating Summer Station is included in "Other operation and maintenance" expenses and totaled approximately $76.4 million for the year ended December 31, 2002.

Planned major maintenance other than that related to nuclear outages is expensed when incurred. The only major maintenance that is accrued in advance of the time the costs are actually incurred is that related to the nuclear refueling outages for which such accounting treatment and rate recovery of expenses accrued thereunder has been approved by the SCPSC. Nuclear outages are scheduled 18 months apart, and SCE&G begins accruing for each successive outage immediately upon completion of the preceding outage. For the outage ended June 2002, SCE&G accrued approximately $0.5 million per month from January 2001 through June 2002 and is now accruing approximately $0.6 million per month for its portion of the outage scheduled in October 2003. Total outage costs for the planned outage in October 2003 are estimated to be approximately $17 million, of which SCE&G will be responsible for approximately $11.3 million. As of December 31, 2002, SCE&G had accrued $3.8 million.

E. Allowance for Funds Used During Construction (AFC)

AFC, a noncash item, 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 8.3%, 8.8% and 8.3% for 2002, 2001 and 2000, 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. Prior to January 1, 2000 revenues related to regulated electric and gas services were recorded only as customers were billed (see Note 2). Unbilled revenues totaled approximately $107.7 million and $81.1 million as of December 31, 2002 and 2001, 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 approximately $25.3 million and $47.4 million at December 31, 2002 and 2001, respectively,

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which amounts are included in "Deferred Debits — Other regulatory assets."

Customers subject to the gas cost adjustment clause are billed based on a fixed cost of gas determined by the SCPSC 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, 2002 and 2001 SCE&G had undercollected through the gas cost recovery procedure approximately $24.6 million and $12.2 million, respectively, which amounts are also included in "Deferred Debits — Other regulatory assets." At December 31, 2002 PSNC Energy had undercollected through the gas cost recovery procedure approximately $10.6 million which amount is also included in "Deferred Debits — Other regulatory assets." At December 31, 2001 PSNC Energy had overcollected through the gas cost recovery procedure approximately $13.8 million which amount is included in "Deferred Credits — Other regulatory liabilities."

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

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:

	2002		2001		2000
SCE&G	2.93	%	2.98	%	2.98	%
GENCO	2.66	%	2.71	%	2.67	%
SCPC	2.14	%	2.60	%	2.58	%
PSNC Energy	4.29	%	4.06	%	4.15	%
Aggregate of Above	3.06	%	3.09	%	3.09	%

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 adopted SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002. The Company considers the amounts categorized by FERC as "acquisition adjustments" to be goodwill as defined in SFAS 142 and ceased amortization of such amounts upon the adoption of SFAS 142. These amounts are related to acquisition adjustments of approximately $466 million recorded on the books of PSNC Energy (Gas Distribution segment) and approximately $40 million recorded on the books of SCPC (Gas Transmission segment). The Company has no other intangible assets subject to amortization as provided in SFAS 142.

If the Company had ceased amortization of acquisition adjustments during all periods presented in the consolidated statements of operations, net income (loss) and basic and

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diluted earnings (loss) per share would have been as follows:

(Millions of dollars, except per share amounts)	2002			2001		2000
Net Income (Loss) as Reported	$	(142	)	$	539	$	250
Amortization of Acquisition Adjustment		—			14		14

Net Income (Loss) as Adjusted	$	(142	)	$	553	$	264

Basic and Diluted Earnings (Loss) Per Share As Reported	$	(1.34	)	$	5.15	$	2.40
Amortization of Acquisition Adjustment		—			.14		.14

Basic and Diluted Earnings (Loss) Per Share As Adjusted	$	(1.34	)	$	5.29	$	2.54

In connection with implementation of SFAS 142, the Company performed a valuation analysis of its investment in SCPC using a discounted cash flow analysis and of PSNC Energy using an independent appraisal. The analysis of the investment in PSNC Energy indicated that the carrying amount of PSNC Energy's acquisition adjustment exceeded its fair value by approximately $230 million as of January 1, 2002. As a result, the Company recorded an impairment charge of $230 million ($2.17 loss per share) in 2002. The charge is reflected on the statement of operations as the cumulative effect of an accounting change.

H. Nuclear Decommissioning

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 approximately $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 the 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.

SCE&G's method of funding decommissioning costs is referred to as COMReP (Cost of Money Reduction Plan). Under this plan, funds collected through rates ($3.2 million in each of 2002, 2001 and 2000) are used to pay premiums on insurance policies on the lives of certain Company personnel. SCE&G is the beneficiary of these policies. Through these insurance contracts, SCE&G is able to take advantage of income tax benefits and accrue earnings on the fund on a tax-deferred basis. 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.

SCE&G records its liability for decommissioning costs in deferred credits. See also discussion below related to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003.

In addition to the above, pursuant to the National Energy Policy Act passed by Congress in 1992 and the requirements of the DOE, SCE&G has recorded a liability for its estimated share of the DOE's decontamination and decommissioning obligation. The liability, approximately $2.0 million and $2.4 million at December 31, 2002 and 2001, respectively, has been included in "Long-Term Debt, net." SCE&G is recovering the cost associated with this liability through the fuel cost component of its rates; accordingly, this amount has been deferred and is included in "Deferred Debits — Other."

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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 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. As such, no excise taxes are included in revenues or expenses in the statements of operations.

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 being amortized as components of "Interest on long-term debt, net" 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 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 expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate solely to regulated operations. Such amounts are recorded in deferred debits and amortized with recovery provided through rates. Deferred amounts for SCE&G, net of amounts previously recovered through rates and insurance settlements, totaled $17.9 million and $24.4 million at December 31, 2002 and 2001, respectively. Deferred amounts for PSNC Energy totaled $7.8 million and $9.1 million at December 31, 2002 and 2001, respectively. The deferral includes the estimated costs associated with the matters discussed in Note 12C.

L. Temporary Cash Investments

The Company considers temporary cash investments having original maturities of three months or less to be cash equivalents. Temporary cash investments are generally in the form of commercial paper, certificates of deposit and repurchase agreements.

M. Commodity Derivatives

Beginning January 1, 2001 the Company began recognizing assets or liabilities for the energy-related derivatives contracts entered into by its subsidiaries when the contracts are executed. The Company records derivatives contracts at their fair value in accordance with SFAS 133, "Accounting for Derivative Investments and Hedging Activities," as amended, and adjusts fair value each reporting period. The Company derives fair value of most of the energy-related derivatives contracts from markets where they are actively traded and quoted. 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 vast majority of the Company's derivatives contracts do not extend beyond two years. (See Note 11). SCPC's tariffs include a purchased gas adjustment (PGA) clause that provides for the

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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 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.

N. New Accounting Standards

The Company adopted SFAS 141, "Business Combinations," and SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002. SFAS 141 requires all acquisitions to be accounted for utilizing the purchase method. SFAS 142 addresses how goodwill and other intangible assets should be accounted for after they have been recorded in the financial statements. (See Notes 1G and 2).

In June 2001, FASB issued SFAS 143, which becomes effective for financial statements issued for fiscal years beginning after June 15, 2002. Accordingly, the Company adopted this standard effective January 1, 2003. SFAS No. 143 applies to legal obligations associated with the retirement of tangible long-lived assets (ARO) and requires the Company to recognize, as a liability, the fair value of an ARO in the period in which it is incurred and to accrete the liability to its present value in future periods.

The Company has determined that it should recognize an ARO related to the decommissioning and dismantling of Summer Station and, effective January 1, 2003, will record an ARO of approximately $110 million, which amount exceeds the previously recorded reserve for nuclear plant decommissioning of $87 million, and a net capital asset of approximately $20 million. Due to the application of SFAS 71, the difference between these amounts will be recorded in regulatory accounts and will have no impact on the Company's results of operations or cash flows.

The provisions of SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," became effective January 1, 2002. This statement requires that one accounting model be used for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired, and broadens the presentation of discontinued operations to include more disposal transactions. There was no impact on the Company's financial statements from the initial adoption of SFAS 144.

SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," was issued in April 2002. The provisions of SFAS 145, among other things, discontinue treatment of gains or losses from the early extinguishment of debt as extraordinary items unless such early extinguishment meets the criteria of Accounting Principles Board Opinion (APB) 30. The Company will adopt SFAS 145 effective January 1, 2003, and does not expect that initial adoption will have any impact on the Company's results of operations, cash flows or financial position.

SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," was issued in July 2002. This statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The Company will adopt

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SFAS 146 effective January 1, 2003, and does not expect that initial adoption will have any impact on the Company's results of operations, cash flows or financial position.

SFAS 148, "Accounting for Stock-Based Compensation — Transition and Disclosure" was issued in December 2002 and amends SFAS 123, "Accounting for Stock-Based Compensation" to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. It also amends the disclosure requirements of SFAS 123 to require prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Company will adopt the disclosure provisions of SFAS 148 effective January 1, 2003, and does not expect that initial adoption will have any impact on the Company's results of operations, cash flows or financial position.

O. Stock Option 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 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, effective January 1, 2003, the provisions of SFAS 148 "Accounting for Stock-Based Compensation — Transition and Disclosure."

P. Earnings Per Share

Earnings (loss) 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 as net income divided 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.

Q. Reclassifications

Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2002.

R. 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. ACCOUNTING CHANGES

As a result of the January 1, 2002 adoption of SFAS 142, the Company recorded a $230 million impairment charge related to the acquisition adjustment recorded in connection with its investment in PSNC Energy. This charge is reflected on the Consolidated Statements of Operations as the cumulative effect of an accounting change. See additional information at Note 1G.

Effective January 1, 2000 the Company changed its method of accounting for operating revenues associated with its regulated utility operations from cycle billing to full accrual. The cumulative effect of this change was $29 million, net of tax. Accruing unbilled revenues more closely matches revenues and expenses. Unbilled revenues represent the estimated amount customers will be charged for service rendered but not yet billed as of the end of the accounting period.

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3. ACQUISITION

Effective January 1, 2000 the Company acquired PSNC Energy in a business combination accounted for as a purchase. PSNC Energy is a public utility engaged primarily in purchasing, transporting, distributing and selling natural gas to approximately 384,000 residential, commercial and industrial customers in 27 of its 28 franchised counties in North Carolina. Pursuant to the Agreement and Plan of Merger, PSNC Energy shareholders were paid approximately $212 million in cash and 17.4 million shares of SCANA common stock valued at approximately $488 million. In connection with the acquisition, 16.3 million shares of SCANA common stock were repurchased for approximately $488 million. The results of operations of PSNC Energy are included in the accompanying financial statements as of January 1, 2000, the effective date of the acquisition. The total cost of the acquisition was approximately $700 million, which exceeded the fair value of the net assets acquired by approximately $466 million (see Note 1G).

4. RATE AND OTHER REGULATORY MATTERS

South Carolina Electric & Gas Company

Electric

In January 2003 the SCPSC issued an order granting SCE&G an increase in retail electric rates of 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually without the approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.

In May 2002 the SCPSC issued an order approving SCE&G's request to increase the fuel component of rates charged to electric customers from 1.579 cents per KWh to 1.722 cents per KWh. The increase reflects higher fuel costs projected for the period May 2002 through April 2003. The increase also provided continued recovery for under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of SCE&G's base load generating plants in winter 2000-2001. The new rates were effective as of the first billing cycle in May 2002. In January 2003 in conjunction with the approval of the above retail rate increase, the SCPSC approved SCE&G's request to reduce the fuel component to 1.678 cents per KWh. This reduction is effective for service rendered on or after February 1, 2003.

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 the years ended December 31, 2002 and 2001 was as follows:

Rate Per Therm		Effective Date
$.993 $.793 $.596 $.728		January-February 2001 March-October 2001 November 2001-October 2002 November-December 2002

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The SCPSC allows SCE&G to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former MGPs. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for SCE&G's gas operations that had previously been recorded in deferred debits. In October 2002, as a result of the annual review, the SCPSC reaffirmed SCE&G's billing surcharge of 3.0 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2005, of the balance remaining at December 31, 2002 of $17.9 million.

Transit

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.

PSNC Energy's benchmark cost of gas in effect during the years ended December 2002 and 2001 was as follows:

Rate Per Therm		Effective Date
$.690		January 2001
$.750		February-March 2001
$.650		April-August 2001
$.500		September-October 2001
$.350		November-December 2001
$.300		January 2002
$.215		February-June 2002
$.350		July-October 2002
$.410		November-December 2002

On January 2, 2003 the NCUC approved PSNC Energy's request to increase the benchmark cost of gas from $.410 to $.460 per therm effective for service rendered on and after January 1, 2003.

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 June 2000 the NCUC approved PSNC Energy's requests for disbursement of up to $28.4 million from PSNC Energy's expansion fund to extend natural gas service to Madison, Jackson and Swain Counties in western North Carolina. PSNC Energy estimates that the cost of this project will be approximately $31.4 million. The Madison County and Jackson County portions of the project were completed by the end of 2002. Through December 31, 2002 approximately $16.9 million had been spent on this project.

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The unused portion of PSNC Energy's expansion fund is recorded in prepaid assets.

South Carolina Pipeline Corporation

5. EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN

Employee Benefit Plans

The Company sponsors a noncontributory defined benefit pension plan which covers substantially all permanent employees. The Company's policy has been to fund the plan to the extent permitted by the applicable federal income tax regulations as determined by an independent actuary.

Effective July 1, 2000 the Company's pension plan was amended to provide a cash balance formula. With certain exceptions employees were allowed to either remain under the final average pay formula or elect the cash balance formula. Under the final average pay formula, benefits are based on years of accredited service and the employee's average annual base earnings received during the last three years of employment. Under the cash balance formula, the monthly benefit earned under the final average pay formula at July 1, 2000 was converted to a lump sum amount for each employee and increased by transition credits for eligible employees. Under the cash balance formula, benefits based upon this opening balance increase going forward as a result of compensation credits and interest credits. The effect of this plan amendment was to reduce the Company's net periodic benefit income for the year ended December 31, 2000 by approximately $3.7 million.

In addition to pension benefits, the Company provides certain unfunded 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 the applicable benefits.

Effective July 1, 2000 PSNC Energy's pension and postretirement benefit plans were merged with SCANA's plans.

In connection with the joint ownership of Summer Station, as of December 31, 2002 and 2001 the Company has recorded within deferred credits a $9.1 million and $8.4 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, 2002 and 2001, the Company has also recorded a $6.4 million and $6.0 million receivable, respectively, from Santee Cooper, representing an estimate of its portion of the unfunded net postretirement benefit obligation.

As allowed by SFAS 87, 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

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Pensions and Other Postretirement Benefits," are set forth in the following tables:

Components of Net Periodic Benefit Cost (Income)

	Retirement Benefits
Millions of dollars	2002			2001			2000
Service cost	$	9.0		$	7.9		$	8.3
Interest cost		39.8			38.5			33.5
Expected return on assets		(77.6	)		(83.5	)		(76.6	)
Prior service cost amortization		6.3			5.8			3.0
Actuarial gain		(4.1	)		(12.8	)		(12.2	)
Transition amount amortization		0.8			0.8			0.8

Net periodic benefit income	$	(25.8	)	$	(43.3	)	$	(43.2	)

	Other Postretirement Benefits
Millions of dollars	2002		2001		2000
Service cost	$	3.1	$	3.0	$	2.7
Interest cost		12.4		12.1		10.2
Expected return on assets		n/a		n/a		n/a
Prior service cost amortization		0.9		0.9		0.8
Actuarial loss		1.1		0.7		—
Transition amount amortization		0.8		0.8		0.8

Net periodic benefit cost	$	18.3	$	17.5	$	14.5

Assumptions

	Retirement Benefits
As of December 31,	2002		2001		2000
Discount rate	6.5	%	7.5	%	8.0	%
Expected return on plan assets	9.5	%	9.5	%	9.5	%
Rate of compensation increase	4.0	%	4.0	%	4.0	%

	Other Postretirement Benefits
As of December 31,	2002		2001		2000
Discount rate	6.5	%	7.5	%	8.0	%
Expected return on plan assets	n/a		n/a		n/a
Rate of compensation increase	4.0	%	4.0	%	4.0	%

Changes in Benefit Obligation

	Retirement Benefits
Millions of dollars	2002		2001
Benefit obligation, January 1	$530.8		$479.3
Service cost	9.1		7.9
Interest cost	39.8		38.5
Plan amendment	—		21.5
Actuarial loss	50.6		19.6
Benefits paid	(34.7	)	(36.0	)

Benefit obligation, December 31	$595.6		$530.8

	Other Postretirement Benefits
Millions of dollars	2002		2001
Benefit obligation, January 1	$166.7		$139.0
Service cost	3.1		3.0
Interest cost	12.4		12.1
Plan participants' contributions	0.9		0.5
Plan amendment	—		1.2
Actuarial loss	10.8		20.1
Benefits paid	(10.5	)	(9.2	)

Benefit obligation, December 31	$183.4		$166.7

Change in Plan Assets

	Retirement Benefits
Millions of dollars	2002		2001
Fair value of plan assets, January 1	$831.6		$894.3
Actual return on plan assets	(130.0	)	(26.7	)
Benefits paid	(34.7	)	(36.0	)

Fair value of plan assets, December 31	$666.9		$831.6

Funded Status of Plans

	Retirement Benefits
Millions of dollars	2002	2001
Funded status, December 31	$ 71.3	$300.8
Unrecognized actuarial (gain) loss	107.5	(155.0	)
Unrecognized prior service cost	83.1	89.4
Unrecognized net transition obligation	3.1	4.0

Net asset recognized in Consolidated Balance Sheet	$265.0	$239.2

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	Other Postretirement Benefits
Millions of dollars	2002		2001
Funded status, December 31	$(183.4	)	$(166.7	)
Unrecognized actuarial loss	42.2		32.5
Unrecognized prior service cost	3.9		4.8
Unrecognized net transition obligation	6.6		7.4

Net liability recognized in Consolidated Balance Sheet	$(130.7	)	$(122.0	)

Health Care Trends

The determination of net periodic other postretirement health care benefit cost is based on the following assumptions:

	2002		2001		2000
Health care cost trend rate	10.0	%	8.5	%	7.5	%
Ultimate health care cost trend rate	5.0	%	5.0	%	5.5	%
Year achieved	2011		2009		2005

The effects of a one-percentage-point increase or decrease in the assumed health care cost trend rates on the aggregate of the service and interest cost components of net periodic other postretirement health care benefit cost and the accumulated other postretirement benefit obligation for health care benefits are as follows:

Millions of dollars		1% Increase		1% Decrease
Effect on health care benefit cost		$0.1		$(0.1	)
Effect on postretirement benefit obligation		1.4		(1.7	)

Due to poor performance in the stock market in recent years, the Company has determined to adjust its long-term expected return on assets to 9.25% for 2003. In developing the expected long-term rate of return assumptions, management evaluated the plan's historical cumulative actual returns over several periods, which have all been in excess of related broad indices, and management anticipates that the plan's investment managers will continue to generate long-term returns of at least 9.25%.

The expected long-term rate of return of 9.25% is based on an asset allocation of 80% with equity managers and 20% with fixed income managers. While the Company believes that the asset allocation will return to those levels, because of market fluctuations, the actual asset allocation as of December 31, 2002 was 70% with equity managers and 30% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio to the targeted allocation when considered appropriate.

Long-Term Equity Compensation Plan

The Long-Term Equity Compensation Plan (the Plan) became effective January 1, 2000. The Plan provides for grants of incentive and nonqualified stock options, stock appreciation rights, restricted stock, performance shares and performance units to certain key employees and non-employee directors. The Plan currently authorizes the issuance of up to five million shares of the Company's common stock, no more than one million of which may be granted in the form of restricted stock.

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A summary of activity related to grants of nonqualified stock options follows:

	Number of Options		Weighted Average Exercise Price
Outstanding — December 31, 1999	—		—
Granted	160,508		$25.53

Outstanding — December 31, 2000	160,508		25.53
Granted	716,368		27.43
Exercised	—		n/a
Forfeited	(74,595	)	26.93

Outstanding — December 31, 2001	802,281		27.10

Granted	1,116,638		27.56
Exercised	(103,677	)	27.12
Forfeited	(97,332	)	27.38

Outstanding — December 31, 2002	1,717,910		27.38

One-third of the options vest on each anniversary of the date of grant until full vesting occurs. The options expire ten years after the grant date. Information about outstanding and exercisable options as of December 31, 2002 follows:

		Options Outstanding
Range of Exercise Prices		Number of Options		Weighted Average Remaining Contractual Life (in years)		Weighted Average Exercise Price
$25.50 to $29.60		1,717,910		8.4		$27.38

		Options Exercisable
Range of Exercise Prices		Number of Options		Weighted Average Exercise Price
$25.50 to $29.60		274,306		$26.91

At December 31, 2001 exercisable options totaled 47,275 at a weighted average exercise price of $25.53. No options were exercisable at December 31, 2000.

The Company applies the intrinsic value method prescribed by APB 25 and related interpretations in accounting for grants made under the Plan. Because all options were granted with exercise prices equal to the fair market value of the Company's stock on the respective grant dates, no compensation expense has been recognized in connection with such grants. If the Company had determined compensation expense for the issuance of options based on the fair value method described in SFAS 123, "Accounting for Stock-Based Compensation," pro forma net income (loss) and earnings (loss) per share would have been as presented below:

	2002			2001	2000
Net income (loss) — as reported (millions)	$	(141.7	)	$539.3	$250.4
Net income (loss) — pro forma (millions)		(143.3	)	538.5	250.3
Basic and diluted earnings (loss) per share — as reported		(1.34	)	5.15	2.40
Basic and diluted earnings (loss) per share — pro forma		(1.35	)	5.14	2.40

For purposes of the above pro forma information, the weighted average fair value at grant date (the value at grant date of the right to purchase stock at a fixed price for an extended time period) for options granted in 2002, 2001 and 2000 was $4.67, $5.13 and $4.43, respectively, and was estimated using the Black-Scholes Option pricing model with the following weighted average assumptions.

	2002		2001		2000
Expected life of options (years)	7		7		10
Risk free interest rate	4.64	%	5.08	%	5.99	%
Volatility of underlying stock	21	%	22	%	21	%
Dividend yield of underlying stock	4.4	%	4.2	%	4.4	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. LONG-TERM DEBT

The annual amounts of long-term debt maturities and sinking fund requirements for the years 2003 through 2007 are summarized as follows:

Year		Amount
		(Millions of dollars)
2003		$413
2004		352
2005		197
2006		177
2007		71

Approximately $35.5 million of the long-term debt payable in 2003 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.

In 2002 SCE&G entered into an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the Lake Murray dam remediation project. The loan agreement provides for interest-free borrowings for costs incurred not to exceed $59 million, with such borrowings being repaid over ten years from the initial borrowing. At December 31, 2002 SCE&G had not yet borrowed under the agreement.

On August 7, 1996 the City of Charleston executed 30-year electric and gas franchise agreements with SCE&G. In consideration for the electric franchise agreement, SCE&G paid the City $25 million over seven years (1996-2002) and donated to the City the existing transit assets in Charleston.

On October 15, 2002 SCE&G transferred its transit system to the City of Columbia. As part of the transfer agreement, SCE&G will pay the City $32 million over eight years (2002-2009) in exchange for a 30-year electric and gas franchise, has conveyed transit-related property and equipment to the City and has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to the City. SCE&G will continue to operate the plant for the City until 2005.

SCE&G has a three-year revolving line of credit totaling $75 million, expiring in 2005, in addition to other lines of credit that provide liquidity for issuance of commercial paper. The three-year lines of credit provide back-up liquidity when commercial paper outstanding is in excess of $175 million.

On January 23, 2003 SCE&G issued $200 million First Mortgage Bonds having an annual interest rate of 5.80% and maturing on January 15, 2033. The proceeds from the sale of these bonds were used to reduce short-term debt and for general corporate purposes.

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

7. SHORT-TERM BORROWINGS

Details of lines of credit (including uncommitted lines of credit) and short-term borrowings at December 31, 2002 and 2001, are as follows:

Millions of dollars			2002			2001
Lines of credit			$	588.0		$	588.0
Unused lines of credit			$	588.0		$	588.0
Short-term borrowings outstanding
	Commercial paper (270 or fewer days)		$	208.8		$	164.8
		Weighted average interest rate		1.40	%		1.97	%

The Company pays fees to banks as compensation for 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. These short-term borrowings are supported by a 364-day revolving credit agreement which expires December 16, 2003. The credit agreement provides for a maximum amount of $125 million to be outstanding at any time. Since the credit agreement expires within one year, commercial paper amounts outstanding have been classified as short-term debt.

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Fuel Company commercial paper outstanding totaled $50.1 million and $50.1 million at December 31, 2002 and 2001, respectively, at weighted average interest rates of 1.38% and 2.06%, respectively.

SCE&G's commercial paper outstanding totaled $127.6 million and $114.7 million at December 31, 2002 and 2001, at weighted average interest rates of 1.40% and 1.95%, respectively.

PSNC Energy's commercial paper outstanding totaled $31.1 million at December 31, 2002, at a weighted average interest rate of 1.42%. PSNC Energy had no commercial paper outstanding at December 31, 2001.

8. 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, could limit the payment of cash 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, 2002 approximately $41 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G's common stock.

In October 2002, six million shares of SCANA common stock were sold, generating net proceeds of approximately $146 million.

Cash dividends on common stock were declared during 2002, 2001 and 2000 at an annual rate per share of $1.30, $1.20 and $1.15, respectively.

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

		Unrealized gains (losses) on securities			Cash flow hedging activities			Accumulated other comprehensive income (loss)
		(Million of dollars)
Balance, December 31, 1999		$	336			—		$	336
	Other comprehensive loss		(197	)		—			(197	)

Balance, December 31, 2000			139			—			139
	Other comprehensive loss		(226	)	$	(26	)		(252	)

Balance, December 31, 2001			(87	)		(26	)		(113	)
	Other comprehensive income		87			27			114

Balance, December 31, 2002		$	—		$	1		$	1

During 2002, $87 million was reclassified from unrealized gains (losses) on securities into net income (loss) as a result of the recording of an impairment in the value of the Deutsche Telekom AG investment. The Company also recognized a loss of approximately $20.6 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the year ended December 31, 2002.

During 2001, $354 million was reclassified from unrealized gains (losses) on securities into net income as a result of the exchange of (available for sale) shares of Powertel, Inc., for shares of Deutsche Telekom AG (DTAG). Also in 2001, $(36) million was reclassified from unrealized gains (losses) on securities into net income as a result of the recording of an impairment of the ITC^DeltaCom, Inc. investment. The Company recognized a loss of approximately $17.1 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the year ended December 31, 2001.

There were no realized gains or losses on securities for the year ended December 31, 2000.

9. PREFERRED STOCK

Retirements under sinking fund requirements are at par values. The aggregate

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annual amount of purchase fund or sinking fund requirements for preferred stock for the years 2003 through 2007 is $2.7 million. The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend.

The changes in "Total Preferred Stock (Subject to purchase or sinking funds)" during 2002, 2001 and 2000 are summarized as follows:

		Number of Shares		Millions of Dollars
Balance at December 31, 1999		231,487		$	11.6
	Shares Redeemed — $50 par value	(11,200	)		(0.6	)

Balance at December 31, 2000		220,287			11.0
	Shares Redeemed — $50 par value	(10,803	)		(0.5	)

Balance at December 31, 2001		209,484			10.5
	Shares Redeemed — $50 par value	(9,511	)		(0.5	)

Balance at December 31, 2002		199,973		$	10.0

On October 28, 1997 SCE&G Trust I (the "Trust"), a wholly owned subsidiary of SCE&G, issued $50 million (2,000,000 shares) of 7.55% Trust Preferred Securities, Series A (the "Preferred Securities"). SCE&G owns all of the Common Securities of the Trust (the "Common Securities"). The Preferred Securities and the Common Securities (the "Trust Securities") represent undivided beneficial ownership interests in the assets of the Trust. The Trust exists for the sole purpose of issuing the Trust Securities and using the proceeds thereof to purchase from SCE&G a like amount of its 7.55% Junior Subordinated Debentures due September 30, 2027. The sole asset of the Trust is such Junior Subordinated Debentures of SCE&G. Accordingly no financial statements of the Trust are presented. The financial statements of the Trust are consolidated in the financial statements of SCE&G. The Guarantee Agreement entered into in connection with the Preferred Securities, when taken together with SCE&G's obligation to make interest and other payments on the Junior Subordinated Debentures issued to the Trust and SCE&G's obligations under the Indenture pursuant to which the Junior Subordinated Debentures were issued, provides a full and unconditional guarantee by SCE&G of the Trust's obligations under the Preferred Securities.

The preferred securities of the Trust are redeemable only in conjunction with the redemption of the related 7.55% Junior Subordinated Debentures. The Junior Subordinated Debentures will mature on September 30, 2027 and may be redeemed, in whole or in part, at any time. Upon the redemption of the Junior Subordinated Debentures, payment will simultaneously be applied to redeem Preferred Securities having an aggregate liquidation amount equal to the aggregate principal amount of the Junior Subordinated Debentures. The Preferred Securities are redeemable at $25 per preferred security plus accrued distributions.

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10. INCOME TAXES

Total income tax expense attributable to income (before cumulative effects of accounting changes) for 2002, 2001 and 2000 is as follows:

Millions of dollars			2002			2001			2000
Current taxes:
	Federal		$	174.6		$	91.2		$	88.2
	State			9.0			11.2			9.2
	Foreign			1.0			—			—

		Total current taxes		184.6			102.4			97.4

Deferred taxes, net:
	Federal			(178.5	)		182.5			29.8
	State			.8			1.7			4.7

		Total deferred taxes		(177.7	)		184.2			34.5

Investment tax credits:
	Deferred — State			5.0			5.0			5.0
	Amortization of amounts deferred — State			(1.7	)		(1.5	)		(1.3	)
	Amortization of amounts deferred — Federal			(4.0	)		(4.0	)		(4.0	)

		Total investment tax credits		(0.7	)		(0.5	)		(0.3	)

Non-conventional fuel tax credits:
	Deferred — Federal			29.8			18.7			9.4

		Total income tax expense	$	36.0		$	304.8		$	141.0

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

Millions of dollars			2002			2001			2000
Income before cumulative effect of accounting change			$	87.9		$	539.3		$	221.2
Total income tax expense:
	Charged to operating expense			121.6			135.2			152.0
	Charged (credited) to other items			(85.6	)		169.7			(11.0	)
Preferred stock dividends				11.2			11.2			11.2

		Total pre-tax income	$	135.1		$	855.4		$	373.4

Income taxes on above at statutory federal income tax rate			$	47.3		$	299.4		$	130.7
Increases (decreases) attributed to:
	State income taxes (less federal income tax effect)			8.5			10.7			11.4
	Non-deductible book amortization of acquisition adjustments			—			5.0			5.0
	Allowance for equity funds utilized during construction			(7.9	)		(5.2	)		(1.0	)
	Deductible dividends — Stock Purchase Savings Plan			(4.5	)		(1.1	)		(1.2	)
	Amortization of federal investment tax credits			(4.0	)		(4.0	)		(4.0	)
	Other differences, net			(3.4	)		—			0.1

		Total income tax expense	$	36.0		$	304.8		$	141.0

The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $751.1 million at December 31, 2002 and $873.9 million at

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December 31, 2001 (see Note 1I), are as follows:

Millions of dollars			2002		2001
Deferred tax assets:
	Nondeductible reserves		$	66.9	$	69.7
	Unamortized investment tax credits			61.0		62.1
	Investments in equity securities			25.0		—
	Deferred compensation			21.2		23.1
	Cycle billing			7.7		8.5
	Other			18.6		16.5

		Total deferred tax assets		200.4		179.9

Deferred tax liabilities:
	Property, plant and equipment			814.4		814.3
	Investments in equity securities			—		133.3
	Pension plan benefit income			93.0		81.1
	Deferred fuel costs			17.9		22.8
	Other			26.2		2.3

		Total deferred tax liabilities		951.5		1,053.8

Net deferred tax liability			$	751.1	$	873.9

The Internal Revenue Service has examined and closed consolidated federal income tax returns of the Company through 1997 and is currently examining the Company's 1998, 1999 and 2000 federal returns. The Company does not anticipate that any adjustments which might result from these examinations will have a significant impact on its results of operations, cash flows or financial position.

11. FINANCIAL INSTRUMENTS

The carrying amounts and estimated fair values of the Company's financial instruments at December 31, 2002 and 2001 are as follows:

		2002				2001
Millions of dollars		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Assets:
	Cash and temporary cash investments	$	396.7	$	396.7	$	212.0	$	212.0
	Investments		231.0		281.3		858.1		944.3
Liabilities:
	Short-term borrowings		208.8		208.8		164.8		164.8
	Long-term debt		3,247.5		3,516.4		3,384.8		3,501.0
	Preferred stock (subject to purchase or sinking funds)		9.9		8.6		10.4		8.5

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

•: Cash and temporary cash investments, including commercial paper, repurchase agreements, treasury bills and notes, are valued at their carrying amount.
•: Fair values of investments and long-term debt are based on quoted market prices of the instruments or similar instruments. For debt instruments for which there are no quoted market prices available, fair values are based on net present value calculations. For investments for which the fair value is not readily determinable, fair value is considered to approximate carrying value. The carrying values reflect the fair values of interest rate swaps based on settlement values obtained from counterparties. Early settlement of

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long-term debt may not be possible or may not be considered prudent.

•: Short-term borrowings are valued at their carrying amount.
•: The fair value of preferred stock (subject to purchase or sinking funds) is estimated on the basis of market prices.
•: Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been taken into consideration.

Investments

SCANA and certain of its subsidiaries hold investments in marketable securities, some of which are subject to SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," mark-to-market accounting and some of which are considered cost basis investments for which determination of fair value historically has been considered impracticable. Equity holdings subject to SFAS 115 are categorized as "available for sale" and are carried at quoted market, with any unrealized gains and losses credited or charged to other comprehensive income (loss) within common equity on the Company's balance sheet. Debt securities and preferred stock with significant debt characteristics are categorized as "held to maturity" and are carried at amortized cost. When indicated, and in accordance with its stated accounting policy, SCANA performs periodic assessments of whether any decline in the value of these securities to amounts below SCANA'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.

At December 31, 2002 SCANA Communications Holdings, Inc. (SCH), a wholly owned, indirect subsidiary of SCANA, held investments in the equity and debt securities of the following companies in the amounts noted in the table below.

Investee	Securities	Basis
		(Millions of dollars)
ITC Holding	3.1 million shares common stock	$	5.8
	645,153 shares series A preferred stock, convertible into 2.6 million shares of common stock		7.2
	133,664 shares series B preferred stock, convertible into 534,656 shares of common stock		4.0
ITC^DeltaCom	566,010 shares of common stock		1.1
	149,077 shares series A 8% preferred stock, convertible in 2005 into 2.6 million shares of common stock		12.7
	Warrants to purchase 506,861.8 shares of common stock		1.1
Knology ^(a)	7.2 million shares series A preferred stock, convertible into 7.5 million shares of common stock		14.1
	14.8 million shares series C preferred stock, convertible into 14.8 million shares of common stock		35.1
	21.7 million shares series E preferred stock, convertible into 21.7 million shares of common stock		40.6
	$43.6 million face amount, 12% senior unsecured notes due 2009, including accrued interest		43.6

In 2002 SCH sold the 39.3 million shares it held in DTAG through a series of market transactions, receiving after-tax proceeds of approximately $433 million. In connection with these sales, SCH determined that the decline in value of its investment in DTAG was other than

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temporary, and SCH recorded impairment losses totaling approximately $182 million.

ITC Holding Company (ITC Holding) holds ownership interests in several Southeastern communications companies. As these securities are not actively traded, determination of their fair value is not practicable. ITC^DeltaCom, Inc. (ITC^DeltaCom) is a regional provider of telecommunications services. Knology, Inc. (Knology) is a broadband service provider of cable television, telephone and internet services.

Derivatives

Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. SFAS 133 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 the derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or quotations from independent parties.

Commodities

The Company uses derivative instruments to hedge anticipated future purchases of natural

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

As a result of adopting SFAS 133, the Company recorded a credit to other comprehensive income (loss) of approximately $23.0 million, net of tax, as the effect of the change in accounting principle (transition adjustment) on January 1, 2001. This amount represents the reclassification of unrealized gains that were deferred and reported as liabilities at December 31, 2000. Substantially all of this amount was reclassified into earnings in 2001 as a component of gas cost.

The Company recognized losses of approximately $20.6 million and $17.1 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the years ended December 31, 2002 and 2001, respectively. These losses were recorded in cost of gas. The Company estimates that most of the December 31, 2002 unrealized gain balance of $2.2 million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in 2003 as a decrease to realized gas cost if market prices remain stable. As of December 31, 2002, all of the Company's cash flow hedges settle by their terms before the end of 2005.

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.

The Company also utilizes certain derivative instruments that do not qualify as hedges. The change in fair value of these derivatives is recorded in net income (loss), and was insignificant in 2002, 2001 and 2000.

Interest Rates

Payments received to terminate a swap are recorded as a basis adjustment to long term debt, and are amortized as reductions to interest expense over the term of the underlying debt. The fair value of interest rate swaps is reflected within other deferred debits on the balance sheet. The fair value of the debt that is hedged is recorded in long-term debt. Receipts or payments related to the interest rate swaps are credited or charged to interest expense as incurred.

The Company received payments to terminate swaps totaling $29.3 million and $6.5 million in 2002 and 2001, respectively. These amounts are being amortized over the ten year term of the underlying debt they formerly hedged. At December 31, 2002 the estimated fair value of the Company's swaps totaled $9.0 million related to combined notional amounts of $344.9 million.

12. COMMITMENTS AND CONTINGENCIES

A. Lake Murray Dam Reinforcement

On October 15, 1999 FERC mandated that SCE&G reinforce its Lake Murray dam in order to comply with new federal safety standards and maintain the lake in case of an extreme

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earthquake. Construction for the project and related activities, which began in the third quarter of 2001 is expected to cost approximately $275 million and be completed in 2005. Costs incurred through December 31, 2002 totaled approximately $67 million.

B. Nuclear Insurance

The Price-Anderson Indemnification Act, which deals with public liability for a nuclear incident, currently establishes the liability limit for third-party claims associated with any nuclear incident at $9.5 billion. Each reactor licensee is currently liable for up to $88.1 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $10 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 $58.7 million per incident, but not more than $6.7 million per year.

The Price-Anderson Indemnification Act expired in August 2002, but is expected to renew with only modest changes in 2003. This has no impact on SCE&G at present due to the "grandfathered" status of existing licensees that are covered under the past act until such time as it is renewed.

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit 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 $15.5 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident at Summer Station. 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.

C. Environmental

South Carolina Electric & Gas Company

At SCE&G, site assessment and cleanup costs are recorded in deferred debits and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $17.9 million at December 31, 2002. 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 benzene contamination in the intermediate aquifer on surrounding properties. SCE&G anticipates that the remaining remediation activities will be completed in 2003, with certain monitoring and retreatment activities continuing until 2007. As of December 31, 2002, SCE&G has spent approximately $18.4 million to remediate the Calhoun Park site. Total remediation costs are estimated to be $21.9 million.

SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by DHEC. SCE&G is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. SCE&G anticipates that major remediation activities for these three sites will be completed before 2006. SCE&G has spent approximately $2.2 million related to these sites, and expects to incur an additional $5.9 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Public Service Company of North Carolina, Incorporated

PSNC Energy owns, or has owned, all or portions of seven sites in North Carolina on which MGPs were formerly operated. Intrusive investigation (including drilling, sampling and analysis) has begun at two sites and the remaining sites have been evaluated using historical records and observations of current site conditions. These evaluations have revealed that MGP residuals are present or suspected at several of the sites. 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 potentially responsible parties (PRP). In September 2002 an allocation agreement was reached relieving PSNC Energy of liability for two of the seven sites. PSNC Energy has recorded a liability and associated regulatory asset of $7.8 million, which reflects the estimated remaining liability at December 31, 2002. Amounts incurred to date that have not been recovered through gas rates are approximately $1.2 million. Management believes that all MGP cleanup costs will be recoverable through gas rates.

D. Franchise Agreements

See Note 6 for a discussion of the electric and gas franchise agreements between SCE&G and the cities of Columbia and Charleston.

E. Claims and Litigation

In 2001 the Company entered into, in the ordinary course of business, a 15 year take-and-pay contract with an unaffiliated natural gas supplier (Supplier) to purchase 190,000 DT of natural gas per day beginning in the spring of 2004. In December 2002, as a result of the failure of Supplier and its guarantor to meet contractual obligations related to credit support provisions, the Company terminated the contract. Attempts to negotiate a new contract between the parties were not successful. In February 2003, the Company received notification from Supplier of its request for binding arbitration under the original contract. The Company is confident of the propriety of its actions and will vigorously pursue its position in such arbitration proceedings. 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.

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.

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 $11.5 million, $12.1 million and $8.8 million in 2002, 2001 and 2000, respectively. Future minimum rental payments under such leases are as follows:

	Millions of dollars
2003	$	15.9
2004		12.3
2005		10.6
2006		10.0
2007		9.7
Thereafter		17.3

	$	75.8

At December 31, 2002 minimum rentals to be received under noncancelable subleases with

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remaining lease terms in excess of one year totaled approximately $11.5 million.

G. Purchase Commitments

Purchase commitments including those commitments under forward contracts for natural gas purchases, gas transportation capacity agreements and coal supply contracts are as follows:

	Millions of dollars
2003	$	1,249.2
2004		317.5
2005		145.5
2006		107.7
2007		93.0
Thereafter		604.8

	$	2,517.7

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

13. 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 comprised of the electric portion of SCE&G, GENCO and Fuel Company and is primarily engaged in the generation, transmission and distribution of electricity. SCE&G's electric service territory extends into 24 counties covering more than 15,000 square miles in the central, southern and southwestern portions of South Carolina. Sales of electricity to industrial, commercial and residential customers are regulated by the SCPSC. SCE&G is also regulated by FERC. GENCO owns and operates the Williams Station generating facility and sells all of its electric generation to SCE&G. GENCO is regulated by FERC. Fuel Company acquires, owns and provides financing for the fuel and emission allowances required for the operation of SCE&G and GENCO generation facilities.

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's operations extend to 33 counties in South Carolina covering approximately 22,000 square miles. PSNC Energy's operations cover 27 counties in North Carolina and approximately 12,000 square miles. 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 directly to industrial customers in 40 counties throughout South Carolina. SCPC also owns LNG liquefaction and storage facilities. Both of these segments are regulated in their respective states of operations.

Retail Gas Marketing markets natural gas in Georgia's restructured natural gas market. Energy Marketing markets electricity and natural gas to industrial, large commercial and wholesale customers, primarily in the Southeast.

Telecommunications Investments holds investments in telecommunication companies.

The Company's regulated reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However Electric Operations' product differs from the other segments, as does its generation process and method of distribution. The gas segments differ from each other 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.

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Disclosure of Reportable Segments

Millions of dollars
2002	Electric Operations	Gas Distribution	Gas Transmission	Retail Gas Marketing	Energy Marketing		Telecom Investments		All Other	Adjustments/ Eliminations		Consolidated Total
Customer Revenue	$1,380	$653	$225	$380	$316		—		$69	$(69	)	$2,954
Intersegment Revenue	613	1	254	—	—		—		6	(874	)	—
Operating Income	417	69	6	n/a	n/a		—		—	22		514
Interest Expense	8	21	5	3	1		$11		1	149		199
Depreciation & Amortization	166	47	6	—	1		—		7	(7	)	220
Income Tax Expense (Benefit)	3	13	—	6	(1	)	(92	)	11	96		36
Net Income (Loss)	n/a	n/a	n/a	14	—		(172	)	2	14		(142	)
Segment Assets	5,567	1,459	318	128	53		380		74	(225	)	7,754
Expenditures for Assets	625	68	17	—	—		—		15	(23	)	702
Deferred Tax Assets	6	6	6	5	2		25		1	(51	)	—

Millions of dollars
2001	Electric Operations	Gas Distribution	Gas Transmission	Retail Gas Marketing	Energy Marketing		Telecom Investments	All Other		Adjustments/ Eliminations		Consolidated Total
Customer Revenue	$1,369	$793	$222	$454	$613		—	$49		$(49	)	$3,451
Intersegment Revenue	576	1	256	—	—		—	8		(841	)	—
Operating Income	419	75	16	n/a	n/a		—	—		18		528
Interest Expense	10	22	6	5	4		$23	2		151		223
Depreciation & Amortization	160	54	7	2	1		—	6		(6	)	224
Income Tax Expense (Benefit)	3	18	4	3	(8	)	169	4		112		305
Net Income (Loss)	n/a	n/a	n/a	7	4		314	(26	)	240		539
Segment Assets	5,034	1,617	335	99	96		784	272		(415	)	7,822
Expenditures for Assets	414	90	21	4	2		—	17		—		548
Deferred Tax Assets	6	—	4	5	6		—	—		(21	)	—

Millions of dollars
2000	Electric Operations	Gas Distribution	Gas Transmission	Retail Gas Marketing	Energy Marketing		Telecom Investments		All Other	Adjustments/ Eliminations		Consolidated Total
Customer Revenue	$1,344	$748	$250	$413	$679		—		$41	$(42	)	$3,433
Intersegment Revenue	318	1	239	—	—		—		9	(567	)	—
Operating Income (Loss)	446	85	28	n/a	n/a		—		—	(5	)	554
Interest Expense	13	20	4	4	2		$23		3	156		225
Depreciation & Amortization	155	53	7	1	—		—		5	(4	)	217
Income Tax Expense (Benefit)	1	23	8	1	(1	)	(4	)	—	113		141
Net Income (Loss)	n/a	n/a	n/a	3	(3	)	(7	)	1	256		250
Segment Assets	4,953	1,628	309	103	215		599		86	(466	)	7,427
Expenditures for Assets	229	58	18	—	—		—		27	29		361
Deferred Tax Assets	6	—	3	5	4		—		1	(19	)	—

Revenues and assets from segments below the quantitative thresholds are attributable to SCE&G's transit operations, which are regulated by the SCPSC, and 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 any of the quantitative

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thresholds for determining reportable segments in 2002, 2001 or 2000.

Management uses operating income to measure segment profitability for regulated operations. For nonregulated operations management uses net income (loss) for this purpose. Accordingly, SCE&G does not allocate interest charges or income tax expense (benefit) to the Electric Operations or Gas Distribution segments. Similarly, management evaluates utility plant for segments attributable to SCE&G and total assets for SCE&G as a whole, as well as for other operating segments. Therefore, SCE&G does not allocate accumulated depreciation, common and non-utility plant, or deferred tax assets to reportable segments. However GENCO and PSNC Energy do have interest charges, income taxes and deferred tax assets, which are included in Electric Operations and Gas Distribution, respectively. Interest income is not reported by segment and is not material. For 2002 and 2000, adjustments to net income and income tax expense include the cumulative effects of the accounting changes described in Note 2.

The Consolidated Financial Statements report operating revenues which are comprised of the energy-related reportable segments. Revenues from non-reportable segments and investment income from Telecommunications Investments are included in Other Income. Therefore the adjustments to total revenue remove revenues from non-reportable segments. Adjustments to Net Income consist of SCE&G's unallocated net income.

Segment assets include utility plant only (excluding accumulated depreciation) for SCE&G's Electric Operations, Gas Distribution and Transit Operations, and all assets for PSNC Energy and the remaining segments. As a result, adjustments to assets include accumulated depreciation, common and non-utility plant and non-fixed assets for SCE&G.

Adjustments to Interest Expense, Income Tax Expense (Benefit), Deferred Tax Assets and Expenditures for Assets include primarily the totals from SCANA or SCE&G that are not allocated to the segments. Interest Expense is also adjusted to eliminate inter-affiliate charges. 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. Deferred Tax Assets are also adjusted to remove the non-current portion of those assets. Expenditures for Assets are also adjusted for AFC.

14. QUARTERLY FINANCIAL DATA (UNAUDITED)

Millions of dollars, except per share amounts
2002	First Quarter			Second Quarter		Third Quarter		Fourth Quarter		Annual
Total operating revenues	$	822		$	649	$	694	$	789	$	2,954
Operating income		153			89		154		118		514
Income (loss) before cumulative effect of accounting change		(72	)		40		78		42		88
Cumulative effect of accounting change, net of taxes⁽¹⁾		(230	)		—		—		—		(230	)
Net income (loss)		(302	)		40		78		42		(142	)
Basic and diluted earnings (loss) per share		(2.88	)		.38		.74		.47		(1.34	)
2001	First Quarter			Second Quarter		Third Quarter		Fourth Quarter		Annual
Total operating revenues	$	1,318		$	740	$	710	$	683	$	3,451
Operating income		173			93		143		119		528
Net income		79			385		63		12		539
Basic and diluted earnings per share		.75			3.67		.61		.12		5.15

(1): The cumulative effect of accounting change is attributable to the adoption of SFAS 142. The amount of the cumulative effect was finalized in the fourth quarter 2002 and, as prescribed in the standard, was recorded effective January 1, 2002. See Note 1G.

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MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS

COMMON STOCK INFORMATION

		2002								2001
		4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.		4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.
Price Range:^(a)
	High	$	31.00	$	31.26	$	32.15	$	30.66	$	27.99	$	28.49	$	29.03	$	30.00
	Low		24.80		23.50		29.05		26.26		25.00		24.25		26.61		24.92

(a): As reported on the New York Stock Exchange Composite Listing.

DIVIDENDS PER SHARE

	2002				2001
	Amount		Date Declared	Date Paid	Amount		Date Declared	Date Paid
First Quarter	$	.325	February 21, 2002	April 1, 2002	$	.30	February 22, 2001	April 1, 2001
Second Quarter		.325	May 2, 2002	July 1, 2002		.30	May 3, 2001	July 1, 2001
Third Quarter		.325	August 1, 2002	October 1, 2002		.30	August 2, 2001	October 1, 2001
Fourth Quarter		.325	October 31, 2002	January 1, 2003		.30	November 1, 2001	January 1, 2002

The principal market for SCANA common stock is the New York Stock Exchange. The ticker symbol used is SCG. The corporate name SCANA is used in newspaper stock listings. The total number of shares of SCANA common stock outstanding at February 28, 2003 was 110,832,747. The number of common shareholders of record at February 28, 2003 was 40,170.

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EXECUTIVE OFFICERS

The executive officers are elected at the annual organizational meeting of the Board of Directors, held immediately after the annual meeting of shareholders, and hold office until the next such organizational meeting, unless a resignation is submitted, or unless the Board of Directors shall otherwise determine. Positions held are for SCANA Corporation and all subsidiaries unless otherwise indicated.

Name	Age	Positions Held During Past Five Years	Dates
W. B. Timmerman	56	Chairman of the Board, President and Chief Executive Officer	*-present
H. T. Arthur	57	President and Chief Operating Officer — SEMI Senior Vice President, General Counsel and Assistant Secretary Vice President, General Counsel and Assistant Secretary	2002-present 1998-present *-1998
G. J. Bullwinkel	54	President and Chief Operating Officer — SCPC and ServiceCare President and Chief Operating Officer — SCI Senior Vice President - Governmental Affairs and Economic Development Senior Vice President - Retail Electric — SCE&G	2002-present -present 1999-2002 -1999
S. D. Burch	46	Senior Vice President - Natural Gas Asset and Procurement Management Deputy General Counsel and Assistant Secretary Attorney	2003-present 2000-2003 *-2000
S. A. Byrne	43	Senior Vice President-Nuclear Operations — SCE&G Vice President-Nuclear Operations — SCE&G General Manager-Nuclear Plant Operations— SCE&G	2001-present 2000-2001 *-2000
D. C. Harris	50	Senior Vice President - Human Resources Vice President - Human Resources — Austin Quality Foods, Inc. Cary, NC	2000-present *-2000
N. O. Lorick	52	President and Chief Operating Officer — SCE&G Vice President - Fossil and Hydro Operations — SCE&G	2000-present *-2000
K. B. Marsh	47	Senior Vice President and Chief Financial Officer President and Chief Operating Officer — PSNC Energy Vice President - Finance and Chief Financial Officer Controller	1998-present 2001-2003 -1998 -2000
C. B. McFadden	58	Senior Vice President - Governmental Affairs and Economic Development Vice President - Governmental Affairs and Economic Development	2003-present *-2003

*: Indicates position held at least since March 1, 1998.

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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.

ACCT #:

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

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

Election of Class I Nominees—
Terms Expire 2006

01-
02-
03-
04-

James A. Bennett
William C. Burkhardt
Lynne M. Miller
Maceo K. Sloan

For ALL Nominees / /
Withhold Authority / /
For ALL EXCEPT the following: / /
(Write number(s) of nominee(s) below)

Approval of Appointment of External Auditors

For / / Against / / Abstain / /

Dated

, 2003

			Sign here X
			exactly as name(s) appears on this card.
	COMPANY NUMBER CONTROL NUMBER		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 May 1, 2003 ............. / / I consent to receive future Proxy Statements and Annual Reports on the Internet ............................................. / /

SCANA CORPORATION
Annual Meeting of Shareholders
May 1, 2003

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 May 1, 2003, 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.

Your vote for the election of Class I Directors may be indicated on the reverse. Nominees are: James A. Bennett, William C. Burkhardt, Lynne M. Miller and Maceo K. Sloan.

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

INSTRUCTIONS FOR VOTING YOUR PROXY
We are now offering shareholders three alternative methods of voting this proxy:
•  By Telephone (using a touch-tone telephone)    •  On the Internet (using a browser)
•  By Mail (traditional method)
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 Savings Time on April 30, 2003
•  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
•  You will be asked to enter ONLY the CONTROL NUMBER shown on the reverse side
•  Have your proxy card ready, then follow the prerecorded instructions
•  Your vote will be confirmed and cast as you directed
INTERNET VOTING    Available until 5:00 p.m. Eastern Daylight Savings Time on April 30, 2003
•  Visit the Internet voting Website at www.proxy.georgeson.com
•  Enter the COMPANY NUMBER AND CONTROL NUMBER shown on the reverse side and follow the instructions on your screen
•  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 the Internet, please do not return your proxy card

ADMISSION TICKET

SCANA CORPORATION
Annual Meeting of Shareholders
May 1, 2003
8:00 A.M.– Refreshments
9:00 A.M.– Meeting Begins
Geneen Auditorium
The Fuqua School of Business
Duke University
One Science Drive
Durham, North Carolina 27708

Valet Parking

From Columbia and southern points
I-77 North to I-85 N; continue on I-85 N to Durham Exit 173. Make a right onto 15-501 South. Continue on 15-501 South until you reach NC 751/Duke University. Turn left onto NC 751. Proceed up the hill to the third traffic light. At the light, make a left onto Science Drive. At the second drive, turn left into the entrance of the R. David Thomas Executive Conference Center.

From Washington and northern points
From I-95 South, go through Richmond to Petersburg, Virginia. Follow signs to I-85 South (Durham). Upon entering the Durham city limits, exit left onto 15-501 South (Duke University/Chapel Hill). Take the NC 751/Duke University Exit. Turn left at NC 751. Proceed up the hill to the third traffic light. At the light, make a left onto Science Drive. At the second drive, turn left into the entrance of the R. David Thomas Executive Conference Center.

From Raleigh-Durham International Airport
Take 1-40 West to Exit 279B (Durham Freeway/NC 147). Continue on the Durham Freeway North toward Durham for approximately 11 miles to Exit 16B (15/501 South). Exit onto 16B and drive approximately 1 mile to Exit 107 (Duke University West Campus and Hospitals). Turn left onto Cameron Blvd. at the traffic light at the end of the exit ramp. At the third traffic light turn left onto Science Drive. At the second drive, turn left into the entrance of the R. David Thomas Executive Conference Center.

Proxy Notification

Dear Shareholder:

During last year's proxy season, you elected to receive our 2003 Proxy Statement and Annual Report electronically.

SCANA Corporation has made available on-line its 2003 annual meeting proxy materials. Please access www.proxy.georgeson.com to review the proxy materials and vote your shares. In order to cast your vote, you will be asked to enter the company number and control number located on the front of the enclosed proxy card. Please direct your attention to the top of the website page where you will find boxes designated for each specific document. Your vote is very important to us. Please remember to cast your vote before exiting the website.

Sincerely,
Shareholder Services
SCANA Corporation

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